Greenhouse Gas Control Technologies - 6th International Conference (Tribology Series, Vol 41)

G R E E N H O U S E GAS CONTROL TECHNOLOGIES

6 th

Proceedings of the International Conference on Greenhouse Gas Control Technologies

1 - 4 October 2002, Kyoto, Japan

Volume H

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G R E E N H O U S E GAS CONTROL TECHNOLOGIES

6 th

Proceedings of the International Conference on Greenhouse Gas Control Technologies 1 - 4 October 2002, Kyoto, Japan

Edited by

J. Gale IEA Greenhouse Gas R&D Programme, Cheltenham, Gloucestershire, UK

Y. K a y a RITE, Kyoto, Japan

Volume H

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0080442765

Library of Congress Cataloging in Publication Data A catalog record from the Library of Congress has been applied for.

ISBN:

0-08-044276-5 (2 volume set)

The paper used in this publication meets the requirements of ANSI/NISO Z39.48-1992 (Permanence of Paper). Printed in The Netherlands.

Foreword

These proceedings contain papers presented or displayed as posters at the 6th International Conference on Greenhouse Gas Control Technologies (GHGT-6) held at Kyoto International Conference Hall, Japan, from October 1 to 4, 2002. Overall, some 240 papers were presented orally and 76 papers were displayed at poster sessions. The conference attracted 500 delegates from 32 countries, of which more than 55% were from countries other than Japan, the host country. Following the plenary session consisting of two keynote speeches on climate change policies and technical measures, six parallel sessions were held for presentation of the 240 papers. The origin of this conference series started in 1992 under the title of the International Conference on Carbon-Dioxide Removal (ICCDR 1). It dealt with studies on carbon dioxide capture and sequestration technologies and was followed by ICCDR-2 held in Kyoto, Japan, in 1994 and ICCDR-3 held at MIT, USA, in 1996. The scope of the conference was broadened in the next conference held in Interlaken, Switzerland, in 1996 so as to include all greenhouse gases and issues related to climate change such as technical, economic and policy measures to mitigate climate change. The name of the conference series was changed at that time to the International Conference on Greenhouse Gas Control Technologies (GHGT-4). GHGT-5 was held in Cairns, Australia, in 2000; both conferences were very successful with more than 200 papers presented respectively. By 1995, the IEA Greenhouse Gas R&D Programme (IEA GHG) had held a similar conference series and decided to support the GHGT series. IEA GHG then became the guardian of the GHGT series. The present conference, GHGT-6, was organized jointly by IEA GHG, the Research Institute of Innovative Technology for the Earth (RITE), Japan, and the Japan Society of Energy and Resources (JSER). Taking into account that JSER's fields of activity include energy economics and general energy technologies, the organizers decided to broaden the scope of the conference so as to accommodate their inclusion. This may be one of reasons why the total number of papers presented at this conference has been the largest in this conference series. The papers included here, therefore, cover broad areas related to climate change issues. About 55% of the papers consist of those in the field of CO2 recovery and sequestration, although the other 45% cover non-CO2 greenhouse gases, forest absorption, biomass and other energy sources, energy technologies including those for conservation, CO2 utilization technologies, and energy policy and economics. It is noticeable that the number of papers on geological sequestration increased dramatically at this conference, compared with previous conferences. A total of 98 papers were presented or displayed at poster sessions at this conference, whereas less than 40 papers were presented at GHGT-4 and GHGT-5. This may reflect the rapid rise in research spending worldwide on topics associated with the geological sequestration of carbon dioxide.

The proceedings also include a keynote speech made at the plenary session. This comprises an overview of R&D technologies for the mitigation of climate change presented by Mr. H. Mitsukawa of the New Energy and Technology Development Organization (NEDO) of Japan. An important feature of the present conference was the holding of two panel sessions, one concerned with public outreach on CO2 sequestration and the other on the role of industries in the strategy for mitigating global warming. Although this was the first such attempt in this conference series, both sessions attracted audiences who enjoyed the, sometimes heated, discussions between the panelists and audience. The conference was supported not only by main sponsors such as the IEA GHG Programme, RITE and JSER, but by many other organizations, both domestic and foreign. They were: • • • • •

• • • • • • • • • • • • • •

Battelle/Pacific Northwest National Laboratory (PNNL) U.S. Department of Energy/The National Energy Technology Laboratory (US DOE/NETL) The Commemorative Association for the Japan World Exposition (1970) ABB Corporate Research (ABB) BP Statoil TotalFinaElf NOVEM (Netherlands Agency for Energy and the Environment) Engineering Advancement Association, Japan Federation of Electric Power Companies, Japan Japan Automobile Manufacturers Association Japan Cement Association Japan Chemical Industry Association Japan Electronics and Information Technology Industry Association Japan Gas Association Japan Iron and Steel Association Japan Society of Industrial Machining Manufacturers Petroleum Association of Japan Japan Electrical Manufacturers Association

We also acknowledge the support of the Ministry of Economy, Trade and Industry of Japan (METI), New Energy and Industrial Technology Development Organization (NEDO), Kyoto Prefecture, the Japan Business Federation, and Kansai Economic Federation. In addition, we would like to acknowledge the contribution of Dr S. Mills in helping to put these proceedings together.

Yoichi Kaya Chairman, Organizing Committee, GHGT-6 Director General, RITE

vii

CONTENTS

Foreword

VOLUME

I

Address to the Opening Session Kelly Thambimuthu

OPENING SESSION

Global Warming Prevention Technologies in Japan (Keynote lecture) Hiroshi Mitsukawa

CO2 CAPTURE - OVERVIEW

Japanese R&D on CO2 Capture Takahisa Yokoyama The CO2 Capture Project: Meeting the Challenge at the Halfway Point Gardiner Hill CO2 Capture and Storage - The Essential Bridge to the Hydrogen Economy D.R. Simbeck

25

Test Results from a CO2 Extraction Pilot Plant at Boundary Dam Coal-Fired Power Station M. Wilson, P. Tontiwachwuthikul, A. Chakma, R. Idem, A. Veawab, A. Aroonwilas, D. Gelowitz, J. Barrie, C. Mariz

31

CO2 CAPTURE - E N E R G Y

A Study of Very Large Scale Post Combustion CO2 Capture at a Refining and Petrochemical Complex M. Simmonds, P. Hurst, M.B. Wilkinson, C. Watt, C.A. Roberts Application of CO2 Removal to the Fischer-Tropsch Process to Produce Transport Fuel George Marsh, Judith Bates, Heather Haydock, Nikolas Hill, Chris Clark, Paul Freund

39

45

Evaluation of CO2 Capture Technology Developments by Use of Graphical Evaluation and Review Technique Takanobu Kosugi, Ayami Hayashi, Tsuyoshi Matsumoto, Keigo Akimoto, Koji Tokimatsu, Hajime Yoshida, Toshimasa Tomoda, Yoichi Kaya Life Cycle Assessment for CO2 Capture Technology from Exhaust Gas of Coal Power Plant Eriko Muramatsu, Masaki Iijima

57

viii Environmental Analysis of Different Options of CO2 Capture in Power Generation from Natural Gas G. Clerici, E. D 'Addario, M. MusicantL G. Pulvirenti, S. Serenellini, M.G. Valdiserri CO2 Capture from Oil Refinery Process Heaters Through Oxyfuel Combustion M.B. Wilkinson, J.C. Boden, T. Gilmartin, C. Ward, D.A. Cross, R.J. Allam, N. IV. Ivens A Workbook for Screening Options to Reduce CO2 Emissions from Existing Power Stations Lindsay Juniper, John Davison

63

69

75

CO2 Control Technologies: ALSTOM Power Approach Timothy Griffin, Alain Bill, John L. Marion, Nsakala ya Nsakala Numerical Investigation of Oxy-Coal Combustion to Evaluate Burner and Combustion Design Concepts E.H. ChuL A.J. Majeski, M.A. Douglas, Y. Tan, K. V. Thambimuthu

87

Evaluation of Characteristics and Economics of CO2-Capturing NOx-Free Repowering System - In the Case of Utilizing Middle Pressure Steam in a Thermal Power Plant Pyong Sik Pak

95

CO2 C A P T U R E

- AMINE ABSORPTION

Carbon Dioxide Capture from Multiple Flue Gas Sources M. Slater, E. West, C.L. Mariz

103

Flue Gas CO2 Recovery and Compression Cost Study for CO2 Enhanced Oil Recovery Masaki Iijima, Takashi Kamijo

109

Oxidative Degradation of Aqueous Monoethanolamine in CO2 Capture Systems Under Absorber Conditions George S. Goff, Gary T. Rochelle Exergy Analysis of Amine-based CO2 Removal Technology F. Geuzebroek, L.H.J.M. Schneider, G.J.C. Kraaijveld Performance and Cost Analysis for CO2 Capture from Flue Gas Streams: Absorption and Regeneration Aspects A. Veawab, P. Tontiwachwuthikul, A. Aroonwilas, A. Chakma

CO2 C A P T U R E

115

121

127

- MEMBRANES

Integration of H2-separating Membrane Technology in Gas Turbine Processes for CO2 Sequestration K. Jordal, R. Bredesen, H.M. Kvamsdal, O. Bolland Production of Hydrogen and Electricity from Coal with CO2 Capture T.G. Kreutz, R.H. Williams, R.H. Socolow, P. Chiesa, G. Lozza

135

141

Removal and Enrichment of CO2 by Novel Facilitated Transport Membrane Using Capillary Membrane Module with Permeation of Carrier Solution M. Teramoto, N. Takeuchi, N. Ohnishi, H. Matsuyama

149

A New Method for CO2 Capture: Frosting CO2 at Atmospheric Pressure D. Clodic, M. Younes

155

Novel Concepts for CO2 Capture with SOFC J.W. Dijkstra, D. Jansen

161

CO2 C A P T U R E - C H E M I C A L R E A C T I O N •

Solid Sorbents for the Reversible Capture of Carbon Dioxide S. Contarini, M. Barbini, G. Del Piero, E. Gambarotta, G. Mazzamurro, M. Riocci, P. Zappelli Carbon Deposition Characteristics of NiO Based Oxygen Carrier Particles for ChemicalLooping Combustor H.J. Ryu, D.H. Bae, G.T. din

169

175

Novel Combustion Cycles Incorporating Capture of CO2 with CaO J.Carlos Abanades, John E. Oakey, Diego Alvarez, Jouni Hdm~ildinen

181

CO2 Capture from the Air: Technology Assessment and Implications for Climate Policy David W. Keith, Minh Ha-Duong

187

Carbon Dioxide Recovery from Flue Gases by Ammonia Scrubbing Xian-Yu Zheng, Yong-Fa Diao, Bo-Shu He, Chang-He Chen, Xu-Chang Xu, Wen Feng

193

GEOLOGICAL STORAGE - OVERVIEW CO2 Storage in the Subsurface L.G.H. van der Meer Geological Storage of CO2: What's Known, Where are the Gaps and What More Needs to be Done John Gale

201

207

Obstacles to the Storage of CO2 Through EOR Operations in the North Sea A.A. Espie, P.J. Brand, R.C. Skinner, R.A. Hubbard, H.I. Turan

213

The IEA Weyburn CO2 Monitoring and Storage Project R. Moberg, D.B. Stewart, D. Stachniak

219

GEOLOGICAL STORAGE - POLICY Fossil Fuels - Zero Emissions Notions on a Policy Strategy - The Dutch Perspective Rob Cuelenaere

227

Geological Carbon Storage: Understanding the Rules of the Underground Elizabeth J. Wilson, David W. Keith

229

A Search for Regulatory Analogs to Carbon Sequestration D.M. Reiner, H.J. Herzog Health, Safety and Environmental Risk Assessment for Geologic Storage of Carbon Dioxide: Lessons Learned from Industrial and Natural Analogues Sally M. Benson, John Apps, Robert Hepple, Marcelo Lippmann, Chin Fu Tsang, Craig Lewis Passing Gas: Policy Implications of Leakage from Geologic Carbon Storage Sites David G. Hawkins

235

243

249

The Quality of a CO2 Repository: What is the Sufficient Retention Time of CO2 Stored Underground Erik Lindeberg

255

Implications of Surface Seepage on the Effectiveness of Geologic Storage of Carbon Dioxide as a Climate Change Mitigation Strategy Robert P. Hepple, Sally M. Benson

261

Global Constraints on Reservoir Leakage Stephen W. Pacala Retention of CO2 in Geologic Sequestration Formations: Desirable Levels, Economic Considerations and the Implications for Sequestration R&D J.J. Dooley, M.A. Wise Integrated Path Towards Geological Storage: TotalFinalElfApproach R. Bouchard, A. Delaytermoz Geologic Sequestration: An Integrated Framework for Assessing Technical, Economic, Public Acceptance, and Policy Issues Natesan Mahasenan, Elizabeth M. Cook, Prasad Saripalli CO2 Capture, Storage and Reuse Potential in Finland T. Koljonen, H. Siikavirta, R. Zevenhoven, L Savolainen The U.S. Department of Energy Carbon Sequestration Research, Development and Demonstration Program David J. Beecy, Scott Klara Potential for Geological Storage of CO2 in The Netherlands Harry C.E. Schreurs

267

273

279

285

291

297 303

GEOLOGICAL STORAGE- AQUIFERS Demonstrating Storage of CO2 in Geological Reservoirs: The Sleipner and SACS Projects Tore A. Torp, John Gale

311

Japanese R&D Project for CO2 Geological Sequestration H. Koide, T. OhsumL M. Uno, S. Matsuo, T. Watanabe, S. Hongo

317

Geological Characterization of CO2 Storage Sites: Lessons from Sleipner, Northern North Sea R.A. Chadwick, P. Zweigel, U. Gregersen, G.A. Kirby, S. Holloway, P.N. Johannessen

321

Reactive Transport Modeling of Geologic CO2 Sequestration at Sleipner James W. Johnson, John J. Nitao

327

The Potential for Storing Carbon Dioxide in the Rocks Beneath the UK Southern North Sea Michelle Brook, Karen Shaw, Ceri Vincent, Sam Holloway

333

Effective CO2 Storage Capacity in Aquifers, Gas Fields, Oil Fields and Coal Fields A. Obdam, L. van der Meer, F. May, C. Kervevan, N. Bech, A. Wildenborg

339

GEOLOGICAL S T O R A G E - MONITORING Monitoring of CO2 Injected at Sleipner Using Time Lapse Seismic Data R. Arts, O. Eiken, A. Chadwick, P. Zweigel, L. van der Meer, B. Zinszner

347

Monitoring Carbon Dioxide Sequestration Using Electrical Resistance Tomography (ERT): A Minimally Invasive Method R.L. Newmark, A.L. Ramirez, W.D. Daily

353

Laboratory Measurements of Seismic Wave Velocity by CO2 Injection in Two Porous Sandstones Ziqiu Xue, Takashi Ohsumi, Hitoshi Koide

359

Geochemical Monitoring of Fluid-Rock Interaction and CO2 Storage at the Weyburn CO2-lnjection Enhanced Oil Recovery Site, Saskatchewan, Canada S. Emberley, I. Hutcheon, M. Shevalier, K. Durocher, W.D. Gunter, E.H. Perkins

365

Crossweli Seismic and Electromagnetic Monitoring of CO2 Sequestration G. Michael Hoversten, Roland Gritto, Thomas M. Daley, Ernest L. Majer, Larry R. Myer

371

Sensitivity and Cost of Monitoring Geologic Sequestration Using Geophysics Larry R. Myer, G. Michael Hoversten, Erika Gasperikova

377

GEOLOGICAL STORAGE - ENHANCED OIL RECOVERY Geologic Storage of CO2 in a Carbonate Reservoir within the Williston Basin, Canada: An Update S. G. Whittaker, B. Rostron Soil Gas as a Monitoring Tool of Deep Geological Sequestration of Carbon Dioxide: Preliminary Results from the EnCana EOR Project in Weyburn, Saskatchewan (Canada) M.H. Strutt, S.E. Beaubien, J.C. Beaubron, M. Brach, C. CardellinL R. GranierL D.G. Jones, S. Lombardi, L. Penner, F. QuattrocchL N. Voltatorni

385

391

Storage of C02 in Depleted Hydrocarbon Reservoirs on Low-permeability Chalk N. Bech, P. Frykman

397

C02 Sequestration in Depleted Oil Reservoirs D. Bossie-Codreanu, Y. Le-Gallo, J.P. Duquerroix, N. Doerler, P. Le Thiez

403

xii

GEOLOGICAL STORAGE - NATURAL ANALOGUES The French Carbogaseous Province: An Illustration of Natural Processes of CO2 Generation, Migration, Accumulation and Leakage Isabelle Czernichowski-Lauriol, H~lkne Pauwels, Philippe Vigouroux, Yves-Michel Le Nindre Natural CO2 Accumulations in Europe: Understanding Long-Term Geological Processes in CO2 Sequestration J.M. Pearce, J. Baker, S. Beaubien, S. Brune, I. Czernichowski-Lauriol, E. Faber, G. Hatziyannis, A. Hildenbrand, B.M. Krooss, S. Lombardi. A. Nador, H. Pauwels, B.M. Schroot Natural CO2 Reservoirs on the Colorado Plateau and Southern Rocky Mountains, USA. A Numerical Model S.P. White, R.G. Allis, J. Moore, T. Chidsey, C. Morgan, W. Gwynn, M. Adams Production Operations at Natural CO2 Fields: Technologies for Geologic Sequestration S.H. Stevens, C. Fox, T. White, S. Melzer, C. Byrer The Ladbroke Grove-Katnook Carbon Dioxide Natural Laboratory: A Recent CO2 Accumulation in a Lithic Sandstone Reservoir Maxwell N. Watson, Naoko Zwingmann, Nicholas M. Lemon

411

417

423

429

435

GEOLOGICAL STORAGE - CODE COMPARISONS Mixing of CO2 and CH4 in Gas Reservoirs: Code Comparison Studies C.M. Oldenburg, D.H. -S. Law, Y. Le Gallo, S.P. White

443

Numerical Investigations of Multifluid Hydrodynamics During Injection of Supercritical CO2 into Porous Media M.D. White, B.P. McGrail

449

Measurements of Feldspar Dissolution Rates Under Supercritical CO2-Water-Mineral System Based on Nanoscale Surface Observation M. Sorai, T. OhsumL M. lshikawa

457

Code Intercomparison Builds Confidence in Numerical Models for Geologic Disposal of CO2 463 Karsten Pruess, Andreas BielinskL Jonathan Ennis-King, Yann Le Gallo, Julio Garcia, Kristian Jessen, Tony Kovscek, David H.-S. Law, Peter Lichtner, Curt Oldenburg, Rajesh Pawar, Jonny Rutqvist, Carl Steefel, Bryan Travis, Chin-Fu Tsang, Stephen White, Tianfu Xu

GEOLOGICAL STORAGE - SAFETY Are Disused Hydrocarbon Reservoirs Safe for Geological Storage of CO2? J.A. Jimenez, R.J. Chalaturnyk

471

Geological Sequestration of CO2: Is Leakage Unavoidable and Acceptable? Michael A. Celia, Stefan Bachu

477

Effects of Supercritical CO2 on the Integrity of Cap Rock I. Okamoto, X. LL T. Ohsumi

483

Xlll

The Long-term Fate of CO2 Injected into an Aquifer Erik Lindeberg, Per Bergmo Building Geomechanical Models for the Safe Underground Storage of Carbon Dioxide in Porous Rock Jurgen E. Streit, Richard R. Hillis

489

495

Mechanical Stability of the Potential CO2 Sequestration Sites in Japan X. Li, H. Koide, T. Ohsumi, Q. Li, Z. Wu

501

Rate of Dissolution due to Convective Mixing in the Underground Storage of Carbon Dioxide J. Ennis-King, L. Paterson

507

Risk and Hazard Assessment for Projects Involving the Geological Sequestration of CO2 K.P. Saripalli, N.M. Mahasenan, E.M. Cook

511

Transmission of CO2- Safety and Economic Considerations John Gale, John Davison

517

Engineering and Economic Assessment of CO2 Sequestration in Saline Reservoirs Neeraj Gupta, Larry Smith, Bruce Sass, Sandip Chattopadhyay, Charles W. Byrer

523

GEOLOGICAL

STORAGE

- ECBM

Fundamental Tests on Carbon Dioxide Sequestration into Coal Seams K. Ohga, K. Sasaki, G. Deguchi, M. Fujioka Methane Displacement Desorption in Coal by CO2 Injection: Numerical Modelling of MultiComponent Gas Diffusion in Coal Matrix J.Q. Shi, S. Durucan

531

539

Economic Assessment of CO2 Sequestration in Coal Seams Sohei Shimada, Teru Matsui, Takeshi Sekiguchi, Yukari Sakuragi

545

The Injectivity of Coalbed CO2 Injection Wells P.A. Fokker, L.G.H. van der Meer

551

CoaI-Seq Project Update: Field Studies of ECBM Recovery/CO2 Sequestration in Coalseams Scott Reeves

557

Comparison of Numerical Simulators for Greenhouse Gas Storage in Coalbeds, Part II: Flue Gas Injection David H.-S. Law, L.H.G. van der Meer, W.D. Gunter Development of a Field Experiment of CO2 Storage in Coal Seams in the Upper Silesian Coal Basin of Poland (RECOPOL) F. van Bergen, H.J.M. Pagnier, L.G.H. van der Meer, F.J.G. van den Belt, P.L.A. Winthaegen, R.S. Westerhoff Surface Facilities Computer Model" An Evaluation Tool for Enhanced Coalbed Methane Recovery Doug Macdonald, Sam Wong, Bill Gunter, Rick Nelson, Bill Reynen

563

569

575

xiv

GEOLOGICAL STORAGE - E N H A N C E D O I L R E C O V E R Y A N D NEW DEMONSTRATION P R O J E C T S Frio Brine Sequestration Pilot in the Texas Gulf Coast Susan D. Hovorka, Paul R. Knox

583

CRUST: CO2 Reuse Through Underground Storage Willem Grootheest, Jan- Willem DO'k, Peter Stollwerk, Harry Schreurs

589

A Cleaner Development: The In Salah Gas Project, Algeria F.A. Riddiford, A. TourquL C.D. Bishop, B. Taylor, M. Smith

595

CO2 Underground Storage for Snohvit Gas Field Development T. Maldal, I.M. Tappel

601

GEOLOGICAL STORAGE - MATCHING SINKS AND SOURCES Defining Optimum CO2 Sequestration Sites for Power and Industrial Plants V.A. Kuuskraa, L.J. Pekot

609

CO2 Geological Storage Economics Guy Allinson, Victor Nguyen

615

Geologic Storage of CO2 from Refining and Chemical Facilities in the Midwestern United States Neerja Gupta, Bruce Sass, Sandip Chattopadhyay, Joel Sminchak, Peng Wang, Tony Espie

621

Mathematical Programming Techniques for Designing Minimum Cost Pipeline Networks for CO2 Sequestration H. Y. Benson, J.M. Ogden

627

Australia's CO2 Geological Storage Potential and Matching of Emission Sources to Potential Sinks J. Bradshaw, G. Allinson, B.E. Bradshaw, K Nguyen, A.J. Rigg, L. Spencer, P. Wilson

633

Worldwide Selection of Early Opportunities for CO2-EOR and CO2-ECBM (1) F. van Bergen, A.F.B. Wildenborg, J. Gale, K.J. Damen Worldwide Selection of Early Opportunities for CO2-EOR and CO2-ECBM (2): Selection and Analysis of Promising Cases Kay Damen, Andrd Faaij, Frank van Bergen, Erik Lysen

639

645

A Decision Support System for Underground CO2 Sequestration P.J.P. Egberts, J.F. Keppel, A.F.B. Wildenborg, M.R.H. Peersmann, C. Hendriks, A.S. van der Waart, C. Byrman

651

Saline Aquifer Storage of CO2 from Major Point Sources - A Danish Case Study Michael Larsen, Niels Peter Christensen, Torben Bidstrup

657

xv

GEOLOGICAL S T O R A G E - MINERALS A Program to Develop CO2 Sequestration via Mineral Carbonation Philip Goldberg, Richard Walters

665

Mineral Carbonation and ZECA L. Jia, E.J. Anthony

671

Carbon Dioxide Sequestration by Aqueous Mineral Carbonation of Magnesium Silicate Minerals S.J. Gerdemann, D.C. Dahlin, W.K. O'Connor Carbon Dioxide/Limestone/Water Emulsion for Ocean and Geologic Sequestration of CO2 Dan S. Golomb

677

683

GEOLOGICAL STORAGE - NEW DEVELOPMENTS Economic Feasibility of Carbon Sequestration with Enhanced Gas Recovery (CSEGR) C.M. Oldenburg, S.H. Stevens, S.M. Benson

691

Methanogenic Activity on Coal and Sequestered CO2 for Enhanced Coalbed Methane Recovery K. Budwill, A. Beaton, M. Bustin, K. Muehlenbachs, W.D. Gunter

697

Carbon Sequestration in Coal Seams in Japan and Biogeochemical Carbon Cycle in Tertiary Sedimentary Basins H. Koide, S. Nishimura, S. SatsumL Z. Xue, X. Li

703

In-situ Gasification, Enhanced Methane Recovery and CO2 Storage in Deep Coal Seams James Hetherington, Kelly Thambimuthu

OCEAN STORAGE

-

709

OVERVIEW

On the Production and Use of Scientific Knowledge about Ocean Sequestration Peter M. Haugan

719

Sensitivity of Sequestration Efficiency to Mixing Processes in the Global Ocean B.K. Mignone, J.L. Sarmiento, R.D. Slater, A. Gnanadesikan

725

The Second Phase of Japanese R&D Program for CO2 Ocean Sequestration Shigeo Murai, Takashi Ohsumi, Fumiyasu Nishibori, Masahiko Ozaki

733

In Situ Experiments of Cold CO2 Release in Mid-depth I. Aya, R. Kojima, K. Yamane, P.G. Brewer, E.T. Peltzer, IlL

739

OCEAN

STORAGE

- NEAR

FIELD

BEHAVIOUR

On the Fate of a Purposefully Disposed CO2 Lake in the Deep Ocean Iker Fer, Peter M. Haugan

747

xvi

Modeling Descending Carbon Dioxide Injections in the Ocean Eric J. Wannamaker, E. Eric Adams

753

Modelling of Biological Impact in Direct Injection of Carbon Dioxide in the Ocean Toru Sato

759

A

Sinking Plume Model for Deep CO2 Discharge G.C. Nihous, L. Tang, S.M. Masutani

765

A Hybrid Numerical Model of LCO2 and CO2 Enriched Seawater Dynamics in the Ocean Induced By Moving-ship Releasing B. Chen, Y. Song, M. Nishio, M. AkaL T. Ohsumi

771

OCEAN STORAGE - EXPERIMENT Research Results from the International Collaboration on Ocean Carbon Sequestration Ocean Engineering G. C. Nihous

779

Plume Experiments and Modelling Eric Adams, Norikazu Nakashiki, Baixin Chen, Toru Sato, Guttorm Alendal

785

International Field Experiment Nozzle and Large Tank Studies S.M. MasutanL M. Nishio, M. Ozaki

791

OCEAN STORAGE

-

IMPACTS/CORAL REEF

Ocean Carbon Sequestration: A Case Study in Public and Institutional Perceptions M.A. de Figueiredo, D.M. Reiner, H.J. Herzog

799

Influence of Ocean CO2 Sequestration on Bacterial Elemental Cycling Richard B. Coffin, Michael T. Montgomery, Thomas J. Boyd, Stephen M. Masutani

805

Evasion of CO2 Injected into the Ocean in the Context of CO2 Stabilization Haroon S. Kheshgi

811

Possibility of High CO2 Fixation Rate by Coral Reef Ecosystems K. Yamada, Y Suzuki, B.E. Casareto, H. Komiyama

817

OCEAN STORAGE - LIQUID AND HYDRATE/MESOCOSM Dual Nature of CO2 Solubility in Hydrate Forming Region R. Kojima, K. Yamane, I. Aya

825

Liquid CO2 Droplet Spectra L. Tang, T.J. Gorgas, S.M. Masutani

831

Experimental Studies on Liquid CO2 Injection with Hydrate Film and Highly Turbulent Flows Behind the Releasing Pipe S. Tsushima, S. HiraL H. Sanda, S. Terada

837

xvii

Development of a Formation Process of CO2 Hydrate Particles for Ocean Disposal of CO2 Satoko Takano, Akihiro YamasakL Keiichi Ogasawara, Fumio Kiyono, Minoru Fujii, Yukio Yanagisawa

843

Impacts of CO2 on Microbial Communities in a Mesocosm Experiment K. TakeuchL alL. SugimorL S. Furukawa, Y. Fujioka, J. Ishizaka

849

Efficiency and Effects of Carbon Sequestration Through Ocean Fertilization: Results from a Model Study Anand Gnanadesikan, Jorge L. Sarmiento, Richard D. Slater

E N E R G Y

855

MODELING

Modeling Greenhouse Gas Energy Technology Responses to Climate Change James A. Edmonds, John Clarke, James Dooley, Son H. Kim, Steven ,I. Smith

863

Prospects for the Application of Energy Models in the Design of Climate Policies J. Harnisch, M. Koch, N. HOhne, K. Blok

869

Multiple Gas Reduction Strategy A. Kurosawa

875

Exploring Implications to 2050 of Energy-Technology Options for China E.D. Larson, P. DeLaquil, Z. Wu, W. Chen, P. Gao

881

CO2 Emission Reduction Effect of Cogeneration System in Commercial and Residential Sectors Considering Long-Term Power Generation Mix in Japan Ryoichi Komiyama, Kenji YamajL Yasumasa Fujii

889

An Optimal Energy and Greenhouse Gas Mitigation Path for South Africa in the Short to Medium Term M.I. Howells, M. Solomon

895

ELSA - Energy Linkage Structure of Asia - A Middle Term Multiregional Model for the Assessments of Energy and Environmental Technology Options Shunsuke Mori, Tomohiro Furuse, Kiyoshi Dowaki

901

Modelling Impacts of New Power Generation Facilities and Renewable Technologies on Greenhouse Gas Emissions in Saskatchewan, Canada Q.C. L in, G.H. Huang, B. Bass

907

Evaluation of Carbon Sequestrations in Japan with a Mathematical Model Keigo Akimoto, Hironori Kotsubo, Takayoshi Asami, Xiaochun LL Motoo Uno, Toshimasa Tomoda, Takashi Ohsumi Assessment of CO2 Emissions Reduction Potential by Using an Optimization Model for Regional Energy Supply Systems Y. GenchL K. Saitoh, N. Arashi, H. Yagita, A. Inaba A Role for Renewables Toward Sustainable Energy Systems Hiromi Yamamoto

913

919

925

xviii

Life Cycle GHG Emissions for FCVS in Japan B. Heffelfinger Reduction Potential of CO2 Reduction by Integrated Energy Service System in Urban Area Considering the Generation Mix of Electric Utility Kazutoshi Ikeda, Kiichiro TsujL Hideharu Sugihara, Jun Komoto

931

937

Ranking of Global Energy Systems as Environmental Countermeasure Takaoshi AsamL Motoo Uno, Norifumi Matumiya, Senji Niwa

943

Environmental Evaluation of Introducing Electric Trolley Buses Yuki Kudoh, Hisashi IshitanL Ryuji Matsuhashi, Yoshikuni Yoshida

949

VOLUME II ENERGY EFFICIENCY - GENERAL Energy Efficiency and Environmental Implications in India's Household Sector B. Sudhakara Reddy Effect on CO2 Reduction of Installation of Outer Skin Surface Technologies in Houses and Office Buildings Tomohiko Ihara, Takashi Handa, Ryuji Matsuhashi, Yoshikuni Yoshida, Hisashi Ishitani Evaluation of RDF Power Generation of Large-area Waste Treatment by LCA Nagisa Komatsu, Tomoko Iwata, Sohei Shimada Contributing to Reduction of CO2 Emissions Through Development of a Heat-integrated Distillation Column M. Nakaiwa, K. Huang, T. Endo, T. OhmorL T. Akiya, T. Takamatsu, S. Beggs, C. Pritchard Effect of Fluctuation of Hot-water Demand on Actual Performance of Home Co-generation System Takeyoshi Kato, Siori Kasugai, Tetsuhisa lida, Wu Kai, Yasuo Suzuoki Literature Survey on Economics of Environmental Friendly Electricity Production Takeyoshi Kato

957

963

969

975

981

987

E N E R G Y EFFICIENCY - INDUSTRY

The Cement Industry and Global Climate Change: Current and Potential Future Cement Industry CO2 Emissions Natesan Mahasenan, Steve Smith, Kenneth Humphreys

995

Improvement in Energy Efficiency of Re-rolling Furnaces for Stainless Steel Industry at Jodhpur, Rajasthan, India UP. Singh

1001

Implementation of a Corporate-wide Process for Estimating Energy Consumption and Greenhouse Gas Emissions from Oil and Gas Industry Operations Susann Nordrum, Arthur Lee, Georgia Callahan

1007

xix

Thermoneutral Co-production of Metals and Syngas without Greenhouse Gas Emissions M. Halmann, A. SteinfeM

1013

An Analytical Method of Constructing Best-mixed Power Generation Systems Reflecting Public Preference R. Akasaka, N. Shikasho, K. Morita, K. Fukuda

1019

Application of the API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry to Examine Potential Emission Reductions K. Ritter, S. Nordrum, T. Shires

1025

Cleaner Production Technology and Bankable Energy Efficiency Drives in Fertilizer Industry in India to Minimise Greenhouse Gas Emissions - Case Study Surendra Kumar

1031

CO2 Reduction in the Ironmaking Process by Waste Recycling and By-product Gas Conversion J. G. Kim, J. O. Choi

1037

ZERO EMISSION P O W E R PLANTS

Clean Coal-fired Power Plant Technology to Address Climate Change Concerns W.A. Campbell, W.H. Richards

1045

An 865 MW Lignite Fired CO2 Free Power Plant - A Technical Feasibility Study Klas Andersson, Henrik Birkestad, Peter Maksinen, Filip Johnsson, Lars StrOmberg, Anders Lyngfelt

1051

Recent Developments on Flue Gas CO2 Recovery Technology Tomio Mimura, Takashi Nojo, Masaki Iij'ima, Takashi Yoshiyama, Hiroshi Tanaka

1057

IGCC - The Best Choice for Producing Low-CO2 Power G. Haupt, G. Zimmermann, R. Pruschek, G. Oeljeklaus

1063

Modeling Infrastructure for a Fossil Hydrogen Energy System with CO2 Sequestration Joan M. Ogden

1069

ECONOMICS A CO2-1nfrastructure for EOR in the North Sea (CENS): Macroeconomic Implications for Host Countries P. Markussen, J.M. A ustell, C- W. Hustad

1077

Economic Modeling of the Global Adoption of Carbon Capture and Sequestration Technologies J.R. McFarland, H.J. Herzog, J. Reilly

1083

Economic Benefits of a Technology Strategy and R&D Program in Carbon Sequestration S. Klara, D. Beecy, V. Kuuskraa, P. DiPietro

1089

xx

Prospects for Carbon Capture and Sequestration Technologies Assuming Their Technological Learning Keywan Riahi, Edward S. Rubin, Leo Schrattenholzer CO2 Storage and Sink Enhancements: Developing Comparable Economics B.R. Bock, R.G. Rhudy, H.J. Herzog Carbon Management Strategies for Existing U.S. Generation Capacity: A Vintage-based Approach R.T. Dahowski, J.J. Dooley

1095

1101

1107

Examining Planned U.S. Power Plant Capacity Additions in the Context of Climate Change J.J. Dooley, R.T. Dahowski

1113

Uncertainties in C02 Capture and Sequestration Costs E.S. Rubin, A.B. Rao

1119

Costs of Renewable Energy and CO2 Capture and Storage John Davison

1125

Costs and Performance of CO2 and Energy Transmission D.J. Freeman, D.A. Findlay, M. Bamboat, J. Davison, I. Forbes

1131

POLICY - OVERVIEW Experience Curves for Environmental Technology and Their Relationship to Government Actions E.S. Rubin, M.R. Taylor, S. Yeh, D.A. Hounshell

1139

Greenhouse Gas Intensity Targets vs. Absolute Emission Targets N. HOhne, J. Harnisch

1145

Canadian Initiatives on CO2 Capture and Storage: Towards Zero Emissions from Fossil Fuels Kelly Thambimuthu, Gilles Mercier, Malcolm Wilson, Bob Mitchell, Mahmuda Ali

1151

Australia's Renewable Energy Certificate System David Rossiter, Karla Wass

1157

Financial Incentives for Climate Neutral Energy Carriers Chris Hendriks, Mirjam Harmelink, Rob Cuelenaere

1163

POLICY - KYOTO PROTOCOL Possible Imperfection of International Emissions Trading Under the Existence of Hot Air Akira Maeda The Effect of Emissions Trading and Carbon Sequestration on the Cost of CO2 Emissions Mitigation Natesan Mahasenan, Michael J. Scott, Steven J. Smith

1171

1177

xxi

CO2 Emissions Trading Market Systems as an Environmental Policy Option and Assessment of its Effect - Evaluating Intertemporal Trading in Particular Kazuya Fujime CDM Investment: Market Actors' Perceptions J. Buen Potential Evaluation of CO2 Emissions Reduction by CDM Projects - Project Design to Provide Benefit to Both Developed and Developing Countries Takanobu KosugL Weisheng Zhou, Koji Tokimatsu Economic Evaluation of Sectoral Emission Reduction Objectives for Climate Change Chris Hendriks, David de Jager, Jochen Harnisch, Judith Bates, Leonidas Mantzos, Matti Vainio New Renewable Energy Innovation Partnerships: Elements of a Constructive Carbon Strategy for Norway's Industry and Government J. Buen

1183

1189

1195

1201

1207

Optimization of Natural-gas Utilization at Lanzhou City in China Tetsuo Tezuka, Cheng Min Xin

1213

Potential for Co-utilisation of Coal with Other Fuels to Reduce Greenhouse Gas Emissions I.M. Smith, d.M. Topper

1219

Commercial Viability of Space Solar Power System as a CDM Project Iwao Matsuoka, Tetsuo Tezuka, Takamitsu Sawa

1225

Study on Effective Institutions to Make CDM Projects Viable Ryuji MatsuhashL Sei Fujisawa, Wataru Mitamura, Yutaka Momobayashi, Yoshikuni Yoshida

1231

Economic and Greenhouse Gas Emissions Assessment of Excess Biomass Extracted from Future Kraft Pulp Mills A. ,~dahl, S. Harvey, T. Berntsson Transportation, CDM, and GHG Emission Reductions Ming Yang, )(in Yu

1237

1243

NON-CO2 GASES An Assessment of the Abatement Options and Costs for Reducing the Emissions of the Engineered Chemicals J. Harnisch, J. Gale, David de Jager, Ole Stobbe

1251

Potential Reduction of Fluorocarbon Emissions Under the Enforcement of New Laws in Japan 1257 T. Hanaoka, Y. Yoshida, R. MatsuhashL H. Ishitani Direct Global Warming Emissions from Flat Panel Display Manufacturing and Reduction Opportunities Scott C. Bartos, C. Shepherd Burton

1263

xxii New Alternative Gas Process Feasibility Study for PFC Emission Reduction from Semiconductor CVD Chamber Cleaning Tatsuro Beppu, Yuki Mitsui, Katsuo SakaL Akira Sekiya

1269

RD&D Implications of Multigas Radiative Forcing Scenarios D. Beecy, I~. Kuuskraa, P. DiPietro

1275

Dynamic Model for the Methane Emission from Manure Storage M.A. Hilhorst, R.M. de Mol

1281

Coal Mine Ventilation Air Methane Catalytic Combustion Gas Turbine S. Su, A. C. Beath, C. W. Mallett

1287

The Effective Management of Methane Emissions from Natural Gas Pipelines S. Venugopal

1293

Nitrous Oxide Emission from Purification of Liquid Portion of Swine Waste Takashi Osada

1299

FUEL CELLS

High Efficiency Carbon and Hydrogen Fuel Cells for CO2 Mitigated Power M. Steinberg, J.F. Cooper, N. Cherepy

1307

Multi-criteria Optimization of On-site Heating, Cooling and Power Generation with Solid Oxide Fuel Cells - Gas Turbine Combined Cycle Units K. Tanaka, M. Buret, D. Favrat, K. Yamada

1311

Optimised CO2 Avoidance Through Integration of Enhanced Oil and Gas Recovery with Solid Oxide Fuel Cells T. Clemens, M. Haines, W. Heidug

1319

An Experimental Investigation into the Use of Molten Carbonate Fuel Cells to Capture CO2 from Gas Turbine Exhaust Gases A. AmorellL M.B. Wilkinson, P. Bedont, P. Capobianco, B. Marcenaro, F. Parodi, A. Torazza

1325

High Efficiency CO2 Separation and Concentration System by Using Molten Carbonate Kazuhiko Itou, Hidehisa TanL Yu Ono, Hidekazu Kasai, Ken-ichiro Ota

1331

RENEWABLE ENERGY

Renewable Energy: Prospects for Supplying Electricity in the Deregulated Market in the Philippines Jude Anthony N. Estiva, Ma. Aileen Leah G. Guzman

1337

Technological Options for Cost-effective and Eco-friendly Power Generation for Development of Remote and Rural Areas in India R. Prasad, D.I). Misra

1343

Greening Electricity Generation in South Africa Through Wind Energy Joe dsamoah

1349

xxiii

Greenhouse Gas Mitigation Opportunities Through the Application of Solar Power in Bangladesh Ahsan Uddin Ahmed Corporate Environmentalism in India: Social and Community Issues R.K. Khullar

1353

1359

BIOMASS

Biomass Energy with Geological Sequestration of CO2: Two for the Price of One? James S. Rhodes, David W. Keith

1371

Modelling Bio-energy with Carbon Storage (BECS) in a Multi-region Version of FLAMES P. Read, J. Lermit, P. Kathirgamanathan

1377

A Life Cycle Analysis of Biomass Energy System Taking Sustainable Forest Management into 1383 Consideration Kiyoshi Dowaki, Shunsuke Mori, Hitofumi Abe, Pauline F. Grierson, Mark A. Adams, Nalish Sam, Patrick Nimiago The Synthesis of Clean Fuels from CO2 Rich Biosyngas Kyu-Wan Lee, Jae-Sung Ryu

1389

Reduced CO2 Mitigation Costs by Multi-functional Biomass Production P. BOrjesson, G. Berndes

1395

New Fuel BCDF (Bio-Carbonized-Densified-Fuel): The Effect of Semi-carbonization T. Honjo, M. Fuchihata, T. Ida, H. Sano

1401

New Renewable Energy Innovation Partnerships: Elements of a Constructive Carbon Strategy for Norway's Industry and Government J. Buen

1407

Carbon Sequestration in Plantations and the Economics of Energy Crop Production: The Case of Salix Production in Sweden G. Berndes, P. BOrjesson, C. Azar

1413

Greenhouse Gas Emissions from Bio-ethanol and Bio-diesel Fuel Supply Systems Haroon S. Kheshgi, David J. Rickeard

1419

BIOTECHNOLOGY AND UTILISATION The Potential Role of Biotechnology in Addressing the Long-term Problem of Climate Change in the Context of Global Energy and Economic Systems James A. Edmonds, John Clark, James Dooley, Son H. Kim, R. Izaurralde, N. Rosenberg, G.M. Stokes The Controlled Eutrophication Process: Using Microaigae for CO2 Utilization and Agricultural Fertilizer Recycling J.R. Benemann, J.C. Van Olst, M.J. Massingill, J.A. Carlberg, J.C. Weissman, D.E. Brune

1427

1433

xxiv

The Improvement of Microalgal Productivity by Reducing Light-harvesting Pigment Analysis of a Phycocyanin-deficient Mutant of Synechocystis PCC 6714 Yuji Nakajima, Shoko Fujiwara, Mikio Tsuzuki

1439

Effective C02 Removal by Chlorella sp.HA-1 in Various Cultivation Methods Ji- Won Yang, Tae-Soon Kwon, Jae- Young Lee

1445

Enzymatic Synthesis of Pyruvic Acid and L-Lactic Acid from Carbon Dioxide Masaya Miyazaki, Hiroyuki Nakamura, Hideaki Maeda

1451

LAND USE AND SINKS

Analysis of Agricultural Greenhouse Gas Mitigation Options Within a Multi-sector Economic Framework R.D. Sands, B.A. McCarl, D. Gillig, G.J. Blanford

1459

CSiTE Studies on Carbon Sequestration in Soils G. Marland, C.T. Garten Jr., W.M. Post, T.O. West

1465

Microagriculture - Biofixation of CO2 Using Nitrogen-fixing Microalgae in Rice Fields Y Ikuta

1471

Possibility of CO2 Fixation on Arid Land in Western Australia K. Yamada, T. Kojima, Y. Egashira, Y Abe, M. Saito, N. Takahashi

1477

UTILISATION - ALGAE CO2 Reforming of Methane Catalyzed by Ni-loaded Zeolite-based Catalysts Satoru Murata, Nobuyuki Hatanaka, Hiroharu lnoue, Koh Kidena, Masakatsu Nomura

1485

Promotion of CO2 Hydrogenation in Fixed Bed Recycle Reactors M.J. Choi, J.S. Kim, S.B. Lee, W.Y. Lee, K.W. Lee

1491

The Use of Marine Macroalgae as Renewable Energy Source for Reducing CO2 Emissions M. Aresta, A. Dibenedetto, I. Tommasi, E. Cecere, M. NarraccL A. PetrocellL C. Perrone

1497

Design Parameters of Solar Concentrating Systems for CO2-mitigating Algal Photobioreactors 1503 Eiichi Ono, Joel L. Cuello

PANEL DISCUSSIONS

Public Outreach on CO2 Sequestration Chair: Paul Freund

1511

The Role of Industry in the Strategy for Mitigating Global Warming Chair: Baldur Eliasson

1525

xxv

POSTER PAPERS COs CAPTURE International CO2 Capture Test Network J.M. Topper

1543

The International Test Centre for Carbon Dioxide Capture (ITC) M. Wilson, P. Tontiwachwuthikul, A. Chakma, R. Idem, A. Veawab, A. Aroonwilas, D. Gelowitz

1547

Development of CO2 Separation Membranes (1) Polymer Membrane Hiroshi Mano, Shingo Kazama, Kenji Haraya

1551

Development of CO2 Separation Membranes (2) Facilitated Transport Membrane Kazuhiro Okabe, Norifumi Matsumiya, Hiroshi Mano, Masaaki Teramoto

1555

Evaluation of Membrane Separation Process of CO2 Recovery Norifumi Matsumiya, Hiroshi Mano, Kenji Haraya

1559

PSA Processes for Recovery of Carbon Dioxide Jong-Nam Kim, Jong-Ho Park, Hee-Tae Beum, Sang-Sup Han, Soon-Haeng Cho

1563

Numerical Study of Boiler Retrofitting to Use Recirculated Flue Gases with 02 Injection L. M.R. Coelho, ,I.L. T. Azevedo, M.G. Carvalho

1567

Precombustion Decarbonisation for Power Generation P. Freund, M.R. Haines

1571

Challenges of Recomissioning a CO2 Capture Pilot Plant in Saskatchewan, Canada Dave Skoropad, Don Gelowitz, Raphael Idem, Bob Stobbs, John Barrie

1575

Novel CO2 Absorbents Using Lithium-containing Oxides Masahiro Kato, Kenji EssakL Sawako Yoshikawa, Kazuaki Nakagawa, Hideo Uemoto

1579

Carbon Dioxide Absorption Contactors: Hollow Fibre Membranes and Packed Absorption Columns David deMontigny, Paitoon Tontiwachwuthikul, Amit Chakma

1583

New Column Design Concept for CO2 Absorbers Fitted with Structured Packings A. Aroonwilas, A. Chakma, A. Veawab, P. Tontiwachwuthikul

1587

Heat Stable Salts and Corrosivity in Amine Treating Units W. Tanthapanichakoon, A. Veawab

1591

Corrosion in CO2 Capture Unit for Coal-fired Power Plant Flue Gas A. Veawab

1595

New Amines for the Reversible Absorption of Carbon Dioxide from Gas Mixture Michele Aresta, Angela Dibenedetto

1599

xxvi Carbon Dioxide Absorption with Aqueous Potassium Carbonate Promoted by Piperazine J. Tim Cullinane, Gary T. Rochelle

1603

GEOLOGICAL STORAGE Effect of Pressure, Temperature, and Aqueous Carbon Dioxide Concentration on Mineral Weathering as Applied to Geologic Storage of Carbon Dioxide Robert G. Bruant Jr., Daniel E. Giammar, Satish C.B. MynenL Catherine ,4. Peters

1609

Advanced Centrifugal Compressors for CO2 Re-injection Plant ,4kinori Tasaki, Tsunenori Sato, Norihisha Wada

1613

Reactivity of Injected CO2 with the Usira Sand Reservoir at Sleipner, Northern North Sea I. Czernichowski-Lauriol, C.A. Rochelle, E. Brosse, N. Springer, K. Bateman, C. Kervevan, J.M Pearce, B. Sanjuan, H. Serra

1617

Carbon Dioxide Sequestration in Saline Brine Formations John M. ,4ndr~sen, Matthew L. Druckenmiller, M. Mercedes Maroto-Valer

1621

The GEO-SEQ Project: A Status Report Larry R. Myer, Sally M. Benson, Charles Byrer, David Cole, Christine A. Doughty, William Gunter, G. Michael Hoversten, Susan Hovorka, James W. Johnson, Kevin G. Knauss, Anthony Kovscek, David Law, Marcelo J. Lippmann, Ernest L. Majer, Bert van der Meet, Gerry Moline, Robin L. Newmark, Curtis M. Oldenburg, Franklin M. Orr, Jr., Karsten Pruess, Chin-Fu Tsang

1625

The lEA Weyburn CO2 Monitoring Project - The European Dimension J.B. Riding, I. Czernichowski-Lauriol, S. Lombardi, F. QuattrocchL C.,4. Rochelle, D. Savage, N. Springer

1629

Preliminary Characterisation of Regional Hydrogeology at the CO2 Sequestration Site of Weyburn (SK-Canada) Y.M. Le Nindre, I. Czernichowski-Lauriol, S. Bachu, T. Heck Use and Features of Basalt Formations for Geologic Sequestration B.P. McGrail, ,4.M. Ho, S.P. Reidel, H.T. Schaef

1633

1637

Evaluation of CO2 Sequestration in Saline Formations Based on Geochemical Experiments and 1641 Modeling Bruce M. Sass, Neeraj Gupta, Sandip Chattopadhyay, Jennifer Ickes, Charles ~ Byrer Capacity Investigation of Brine-bearing Sands for Geologic Sequestration of CO2 Christine Doughty, Sally M. Benson, Karsten Preuss Cost Comparison Among Concepts of Injection for CO2 Offshore Underground Sequestration Envisaged in Japan Hironori Kotsubo, Takashi Ohsumi, Hitoshi Koide, Motoo Uno, Takeshi Ito, Toshio KobayashL Kozo lshida

1645

1649

Rate of Dissolution Due to Convective Mixing in the Underground Storage of Carbon Dioxide 1653 J. Ennis-King, L. Paterson

xxvii

Potential Effect of CO2 Releases from Deep Reservoirs on the Quality of Fresh-water Aquifers 1657 P.R. Jaffe, S. Wang Economics of Acid Gas Reinjection: An Innovative CO2 Storage Opportunity Sam Wong, David Keith, Edward Wichert, Bill Gunter, Tom McCann

1661

OCEAN STORAGE Advances in Deep-ocean CO2 Sequestration Experiments P.G. Brewer, E.T. Peltzer, G. Rehder, R. Dunk

1667

Study on CO2 Hydrate Formation as Stockpiling in Marine Sediments Hironori Haneda, Yoshitaka Yamamoto, Takeshi Komai, Kazuo Aoki, Taro Kawamura, Koutaro Ohga

1671

Measurements of CO2 Solution Density Under Deep Ocean and Underground Conditions M. Nishio, Y. Song, B. Chen

1675

Estimations of Interfacial Tensions Between Liquid CO2 and Water from the Sessile-Drop Observations T. Uchida, R. Ohmura, S. Takeya, J. Nagao, H. Minagawa, T. Ebinuma, H. Narita Lethal Effect of Elevated pCO2 on Planktons Collected from Deep Sea in North Pacific Y. Watanabe, A. Yamaguchi, H. Ishida, T. Ikeda, J. Ishizaka Thermodynamic Relationship to Estimate the Effects of High CO2 Concentration on the CO2 Equilibrium and Solubility in Seawater C.S. Wong, P.Y. Tishchenko, W.K. Johnson The GOSAC Project to Predict the Efficiency of Ocean CO2 Sequestration Using 3-D Ocean Models James C. Orr, Olivier Aumont, Andrew Yool, Gian-Kasper Plattner, Fortunat Joos, Ernst Maier-Reimer, Marie-France Weirig, Reiner Schlitzer, Ken Caldeira, Michael Wickett, Richard Matear, Bryan Mignone, Jorge Sarmiento, John Davison Effects of CO2 on Marine Fish J. Kita, A. Ishimatsu, T. Kikkawa, M. Hayashi

1679

1683

1687

1691

1695

E N E R G Y EFFICIENCY

Analysis of Ways of Energy Consumption Reduction While Carbon Dioxide Recovery from Flue Gas by Absorption Methods to Solve the Greenhouse Problems losif L. Leites Making Tourism in New Zealand Energy-efficient- More Than Turning Off the Lights S. Becken Study of Highly Efficient Gas Engine Driven Heat Pump System with Cascaded Use of Exhaust Heat from Engine Kazumi Takahata, Takeshi Yokoyama

1701

1705

1709

XXVIll

Analysis of Cogeneration Network Systems Effective for Reducing Greenhouse Gases Kei Kawakami, Takemi Chikahisa, Yukio Hishinuma

1713

Logics and Logistics of Life Cycle Assessment (LCA) for Minimizing Green House Gas Emissions - An Indian Case Study of Automobile Sector Sita Anand, Surendra Kumar

1717

Energy Saving in Energy Sector of the Republic of Karelia (North-West Russia) S. Y. Kulagin

1721

Reducing Greenhouse Emissions by Inherently Safe Nuclear Reactors A.R. Kenny

1725

Integrated Carbonation: A Novel Conception to Develop a CO2 Sequestration Module for Power Plants M. Mercedes Maroto- Valer, Matthew E. Kuchta, Yinzhi Zhang, John M. Andrdsen

1729

ECONOMICS

Economics of CO2 Capture from a Coal-fired Power Plant- A Sensitivity Analysis D. Singh, E. Croiset, P.L. Douglas, M.A. Douglas

1735

ENERGY MODELLING

Modelling Climate Change and Population Growth on GHG Emissions from the Energy Sector in the Toronto-Niagra Region, Canada Q. G. Lin, B. Bass, G.H. Huang

1741

Development of D.atabase on Japanese Sectoral Energy Consumption, CO2 and Air Pollutant Emission Intensities Based on the Input-output Tables Keisuke Nansai, Yuichi Moriguchi, Susumu Tohno

1745

Analysis of Market Growth Condition for Future Type of Vehicles Based on Consumer Characteristic Model Takemi Chikahisa, Yukio Hishinuma

1749

POLICY

Transportation, CDM, and GHG Emission Reductions Ming Yang, Xin Yu

1755

Emerging Carbon Offset Markets: Prospects and Challenges Patrick Karani

1761

Planning for the Diffusion of Technologies to Capture and Dispose of Carbon Elizabeth L. Malone

1765

An Analysis on CO2 Reduction Effects of Introducing Green Taxation to Car Ownership Tax Yoshikuni Yoshida, Akira Morishita, Ryuji Matsuhashi, Hisashi Ishitani

1769

xxix A Framework for Greenhouse Gas Related Decision-making with Incomplete Evidence A.J.P. Fletcher, J.P. Davis, W.W. Shenton, B. Han, J. Pang

1773

Complex Problems with Incomplete Evidence - Modelling for Decision-making A.J.P. Fletcher, J.P. Davis, W.W. Shenton, B. Han, J. Pang

1777

The Need for Renewable Energy with Emphasis on Solar in Rural Uganda Robert Kabaseke

1781

NON COs - GASES

The Non-CO2 Greenhouse Gases Network John Gale, Francisco de La Cheshnaye, Matti Vianio Reduction of Methane Production from Dairy Cows by Decreasing Ruminal Degradability of Concentrated Ingredients M. Kurihara, T. Nishida, A. Purnomoadi

1787

1791

Dynamic Model for the Methane Emission from Manure Storage M.A. Hilhorst, R.M. de Mol

1795

Separation Process of Hydrofluorocarbons (HFCs) by Clathrate Hydrate Formation Taku Okano, Kazuhiro Shiojiri, Minoru Fujii, Akihiro Yamasaki, Fumio Kiyono, Yukio Yanagisawa

1799

Low Temperature PFC Destruction System Using Surface Discharge Plasma with Catalyst Toshiaki Kato, Tatsufumi Mori, Ryu-ichiro Ohyama, Jun Tamaki

1803

Simplified Monitoring Technique of HFC Mixed Gases in a Coolant Recycle System Yoshiya Iida, Makoto Morita

1807

RENEWABLE ENERGY

CSIRO's Advanced Power Generation Technology Using Solar Thermal- Fossil Energy Hybrid Systems R. Benito, G.J. Duffy, K.T. Do, R. McNaughton, J.H. Edwards, N. Dave, M. Chesnee, C. Walters Solar Technology in Uganda for Reducing CO2 Emissions Wilbrod Birabwa

1813

1817

BIOMASS

Fossil Fuel Consumption and Biomass Energy Sources in Sri Lanka G.K. Winston de Silva, Tissa Ranasinghe Processing of Non Purified Ethanol from a Glucose Fermentation Process for Solid Oxide Fuel Cell Application Raphael Idem, Hussam Ibrahim, Paitoon Tontiwachwuthikul, Malcolm Wilson An Experimental Study on Biomass Coal Briquetting Process Yongliang Ma, Kangfu Xu, Jiming Hao

1823

1825

1829

XXX

New Fuel BCDF (Bio-Carbonized-Densified-Fuel):The Effect of Semi-Carbonization T. Honjo, M. Fuchihata, T. Ida, H. Sano Evaluation of Technology of Generating Electricity with Woody Biomass - Estimate of Reduction in CO2 Emission T. Ogi, Y. Dote

1833

1837

Carbon Sink and Storage Capacity of Forest Ecosystems in Oze, Central Japan Atsushi Hirano, Makoto Tsuchida, Michio Ishibashi, Kazuhiko Ogino

1843

Study of Durable Catalyst for Methane Reforming Using CO2 Takumi Tanaka, Zhaoyin Hou, Osamu Yokota, Tatsuaki Yashima

1847

Mitigation Potential for Carbon Sequestration Through Forestry Activities in Russia D.G. Zamolodchikov, G.N. Korovin, A.I. Utkin

1851

Forestal Biomass: Possible Extension of the Resource of Wood from Thinning in Forests H. Sano, T. Honjou, T. Ida, M. Futihata

1855

Economic Analysis of Carbon Sequestration in Cherrybark Oak in the United States Ching-Hsun Huang, Gary D. Kronrad

1859

International Network for Biofixation of CO2 and Greenhouse Gas Abatement with Microalgae P. PedronL J. Davison, H. Beckert, P. Bergman, J. Benemann

1863

CO2 Emission Reduction and CO2 Fixation on the Ground by Using Supercritical Carbon Dioxide as an Alternative to Organic Solvents Masaaki Yoshida, Masayuki Ohsaki, Naohisa Yanagihara

1867

Utilization of Carbon Dioxide for Neutralization of Alkaline Wastewater S.K. ChoL K.S. Ko, H.D. Chun, J.G. Kim

1871

Author Index

1875

ENERGY EFFICIENCYGENERAL

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

957

E N E R G Y EFFICIENCY AND E N V I R O N M E N T A L IMPLICATIONS IN INDIA'S H O U S E H O L D SECTOR B.Sudhakara Reddy Indira Gandhi Institute of Development Research, Goregaon (E), Mumbai 400 065, India e-mail:[email protected]

ABSTRACT

This present paper provides a methodological framework for estimating the costs and benefits to the household sector through the replacement of the existing inefficient technologies with efficient ones, and suggests policy measures. Annualised Life Cycle Costs (ALCC) are calculated taking into consideration the capital cost of the device, its life, operating cost, energy carrier price, etc. using a 12% discount rate. The results show that the average discounted payback period for many of these technologies, at the current capital costs, is less than two years which usually considered warranting the investment. It is seen from the results that, on average, for every hundred rupees of capital invested on efficient lighting systems, the consumer gets an annual return of about Rs.60. This shows that the rate of return on investment is very high. The paper identifies the barriers that prevent the government from achieving its energy efficiency goals, analyzes programs that address these barriers, and explores the creation of an institutional mechanism.

INTRODUCTION

Energy efficiency improvements have multiple advantages such as the efficiency of utilisation of natural resources, reducing air pollution levels, and reduced spending by the consumer on energy related expenditure. Despite these significant benefits, the government and the utilities are not integrating efficiency programmes into their planning process. From the consumers' perspective, several barriers prevent them from investing in cost-effective energy technologies. The reasons include (1) lack of initial investment for efficient technologies and (ii) lack of sufficient perceived incentives to pursue energy efficiency investments. As a result, the country is missing out on opportunities to save both in terms of energy and the environment. In the present paper, we assess the energy efficiency technologies and their implementation based on three criteria: (i) awareness: propagating the incentives to consumers, (ii) capital constraints: How readily available is funding; and (iii) institutional mechanism: the difficulties in the process of implementation? This new paradigm, with emphasis on energy efficiency, entails the demand for energy from consumer side and switches the focus from energy supply to demand management. A 10-year planning horizon is considered here to study the impact of various technologies on the economy as well as on the environment. This is an attempt to evolve a rational basis for deciding how each stakeholder can benefit from each technology so that costs and benefits can be shared among various stakeholders.

958 INDIA'S ENERGY CONSUMPTION - IMPORTANCE OF HOUSEHOLD SECTOR

India mainly depends on coal, oil and fuel wood for most of its energy needs. In the year 2000, the total energy demand stood at 1.5 million tera joules (MTJ). Of the total, about 65% came from commercial sources and the rest from non-commercial sources such as fuel wood, agriculture wastes, etc. Households are the major consumers with nearly 44% of total energy followed by industry with around 40%. In the household sector, wood-based fuels accounted for 75% and the rest is through kerosene and LPG. The type of fuel used by a household varies with income (Anon, 2000). Low-income groups depend mainly on firewood (in rural as well as urban areas) while the middle income groups depend on fuelwood in rural areas and on kerosene in urban areas. The high income groups depend mainly on LPG in urban areas. METHODOLOGICAL

FRAMEWORK

Energy Efficiency involves the replacement of inefficient technologies with efficient ones and fuel switching from non-renewables to renewable technologies. In the residential sector, major alternatives would be fuel switching- from firewood to kerosene/LPG for cooking, and replacement of existing inefficient devices with efficient ones (for cooking, lighting, water heating, etc. particularly in rural regions where cooking/heating is done using fuelwood with efficiencies as low as 10%. Efficiencies as high as 30% can be achieved through improved stoves with negligible costs. We have developed a framework for analyzing various energy efficiency technologies available in India that are relevant for the residential sector. Various economic criteria are used here to evaluate cost effectiveness of energy efficient technologies. This criterion assesses the technologies with respect to the beneficiaries. Specifically, we assess the savings through each technological shift based on (i) annualised life costs, (ii) the rate of return on investment to the consumer and (iii) total savings that typically accrue to the government and the society. The benefits through each technology by the terminal year 2010 have been calculated as follows: Bi =

(Es * UCSs )* Iu

where Bi =

Benefits through ith technology in the terminal year

Eu = Energy savings per unit UCSs = Avoided cost per unit cost of energy saved Iu = Incremental Units by the terminal year The incremental units are the difference between the market saturation with and with out the programme.

FINANCIAL BENEFITS Here, we examine here different energy carriers (in terms of devices) used by different households and calculate the Annualised Life Cycle Cost, taking into consideration the capital cost of the device and its life, operating cost, operating efficiency, energy carrier price, etc. Since the ALCC includes capital cost, operation and maintenance costs, it is easy to compare the cost of appliances whose performance characteristics are similar. It is seen from Table 1 that on an average, every hundred rupees of capital invested on efficient fuel wood technology the household gets an annual return of about Rs. 64, whereas the shift from fuelwood to biogas produces an annual rate of return

959 of about Rs.34 In the case of lighting technologies, the average annual rate of return is about Rs.60. Thus, from a financial perspective, these technologies are attractive investments for an individual household. ENVIRONMENTAL BENEFITS

Energy efficiency creates an environmental benefit by reducing emissions of air pollutants. Environmental problems in India reflect the pattern of energy utilisation.. India's electricity is primarily generated by coal. Burning fossil fuels emits large amounts of airborne pollutants, primarily carbon dioxide, sulfur dioxide, and nitric oxides. On the basis of consumption by various types of fuels, the CO2 emissions were estimated using the emission coefficients (tC/toe): coal 1.08; oil - 0.86 and gas 0.62. Table 1 indicates the level of emission reduction the household avoids each year as a result of energy efficiency technologies. For example, each household using fuelwood emits 2,184 kg less carbon dioxide per year than would have been emitted had efficient fuelwood technologies not been implemented. Table 2 indicates the costs and benefits through various technological shifts. FACTORS T H A T A F F E C T E F F I C I E N T T E C H N O L O G Y P E N E T R A T I O N A question that such results often arouse is "if it is so economically beneficial and environmentally sound, why don't customers adopt energy efficient technologies on their own?" and "why the government doesn't take initiatives to spread awareness about energy efficiency and help in reducing the energy consumption levels"? Obviously there must be some barriers to adoption. From the consumers' perspective, the availability of capital for the installation of efficient technology, limitations of information, availability about the costs and benefits of the efficient technologies, and uncertainties about the future energy carrier prices are the major barriers. Since efficient devices are expensive, reduction in capital costs through subsidies, rebates, etc., can induce poorer households to shift to more efficient and energy conserving devices. This will also reduce the stress on natural resources. Another possibility will be for the government or electricity boards to install energy efficient equipment in households and collect the payments in monthly installments so that the generation costs could be avoided. However, the consumer's knowledge regarding the costs, benefits, etc., also plays a significant role in the faster diffusion of efficient technologies. The government should try to educate the consumers in understanding the trade-off between the capital cost of the efficient device and the future energy savings. CONCLUSIONS An energy efficiency scenario has been developed for the household sector in India with a ten-year perspective, i.e. 2010A.D according to which the energy saving of 757 PJ is possible. The equivalent cost of saved energy is Rs 10,000/GJ which is much lower than the capital investment required for supplying energy, typically ranging around ten times higher. From the consumer point of view most of the technologies are cost effective with a payback period of about two years. Also, energy efficiency programs offer the largest rewards to the society in the form of emission reductions. To achieve the goal of efficiency, an institutional mechanism should be evolved through which the existing fragmented limited scale markets should be transformed into a greater and more flexible one. Such an institution should act as a coordinator between various stakeholders such as the customer, electric utility, energy supply agencies, equipment manufacturers and other key players. For this to happen, new tools and new rules must be explored that can overcome the critical market barriers to promote energy efficiency programmes. In the light of all the changes that the energy industry is undergoing, the usefulness of integrated resource planning, and its success in meeting the goals of the customer, the government and the society will be based largely on the quantum of involvement of all players in this field --- electric utilities, oil companies, forest departments, consumers, equipment

960

manufacturers, financial institutions, researchers, planners and finally the government.

REFERENCES

1.

Anon, 2001, Results

o f the National S a m p l e

Survey

Organisation

for the Household

Sector, N S S O , G o v e r n m e n t o f I n d i a , N e w D e l h i . S e c t o r , C e n t r e f o r M o n i t o r i n g Indian E c o n o m y , N e w D e l h i .

2.

CMIE, 2001, India's Energy

3.

R e d d y A . K . N . " B a r r i e r s to i m p r o v e m e n t s in e n e r g y e f f i c i e n c y " ,

Energy Policy, 19

(10), 953-

961 ( 1 9 9 1 ) . 4.

Sudhakara

Reddy.B.

households",

"Consumer

Discount

TABLE COSTS From

rates

and

InternationalJournal of Energy Research, 2 0

AND BENEFITS

To Incremental investment (Rs.)

Savings (Rs.)

THROUGH

energy

carrier

choices

in

urban

(2) ( 1 9 9 6 ) .

1 VARIOUS

TECHNOLOGIES

Annual ROI (%) Payback Incremental Energy Unit cost of Carbon rate of period cost (Rs.) saved (G J) energy Emissions return (%) (years) saved (Tons) (Rs./GJ)

Cooking: Wood - TS Wood - TS Kerosene - KS Wood - TS Kerosene- KS Wood - TS Kerosene - KS

Wood- ES Kerosene - TS Kerosene - ES Biogas Biogas LPG stoves LPG stoves

225 100 125 9975 9875 1975 1875

937.7 279.5 543.1 - 133.1 -652.6 -357.6 -637.1

62.22 18.55 44.25 27.34 -66.09 -23.73 -51.91

416.75 279.55 434.51 6.18 -6.61 -18.10 -33.98

0.24 0.36 0.23 16.17 -15.13 -5.52 -2.94

37.3 20.5 16.9 1268.1 1247.6 248.1 227.6

16.0 17.3 3.2 23.8 5.2 20.1 2.8

2.33 1.19 5.35 53.33 240.99 12.35 80.29

Wood - TS Wood - TS Kerosene - KS Wood - TS Kerosene - KS Wood - TS

IWood - ES Kerosene - TS Kerosene - TS SWH SWH Biogas

225 1oo 125 11975 11875 9975

337.7 153.5 415.1 -1005.0 -1158.5 616.9

44.61 20.29 68.80 -132.77 -192.00 27.34

150.08 153.55 332.11 -8.39 -9.76 6.18

0.67 0.65 0.30 -11.92 -10.25 16.17

37.3 20.5 16.9 1755.0 1734.5 1268.1

8.8 9.6 2.4 12.8 3.2 23.8

4.24 2.14 6.94 137.11 535.34 53.33

Wood - TS Kerosene- KS EWH

EWH iEWH SWH

2475 2375 9500

-641.8 -795.4 -363.1

-84.79 - 131.82 -25.96

-25.93 -33.49 -3.82

-3.86 -2.99 -26.16

311.8 291.4 1443.1

11.5 1.9

27.10 149.88

1.3

-

163 217 209

241.3 404.2 253.5

68.48 70.50 44.21

0.68 0.54 0.82

21.5 33.8 42.1

0.3 0.5 0.4

68.11 64.22 118.76

Water Heating:

Lighting (at 5 Hours Usage per Day): IB (60W) IB (IOOW) IB (100 Watt)

CF (I0 Watt) ICFL(18 Watt) FL (36 Watt)

Note: TS: Traditional Stove ES: Efficient Stove EWH: Electric water heater SWH: Solar water heater IB: I n c a n d e s c e n t B u l b CFL: Compact fluorescent lamp FL: Fluorescent lamp

148.05: 186.29i 121.30!

0.58 0.63 0.06 0.86 0.10 0.63 0.05 0.00 0.32 0.18 0.05 0.46 0.06 0.86 0.42 0.04 0.02 0.00 0.005 0.009 0.006

961

TABLE 2 IMPACT OF EFFICIENT TECHNOLOGIES Energy Carrier

]Investm:nt~6~nnualCost IAnnual Rate [Incremental Rs. [Ml(l~illi°n~ [Savings (Rs. ~ofRetum ~ost (Rs. Savings [Million) I(%) [Million) Wood Kerosene Electricity (mt) ((million l) (GWh)

Cooking/heating- rural Firewood

7354

Kerosene

35940

828

3616

47414 I

28022]

57 35

1003

37.95 437.11

50

Total (PJ)

% of total

CO2 Emissions abated (mt)

607.12

80.30

63.75

15.3

2.02

1.08

41.02

5.42

12.19

36.24

4.79

3.81

19.44

2.57

1.37

37.8

4.99

11.42

Lighting - rural Electricity]

55 !

11201

3482

Cooking/heating - urban Firewood

439

Kerosene

1052

2146

60

4595

35

63

28115

50

3365

2.27 19.44

Lighting - urban Electricity rotal

51542 108629

Cost of savings

102433

8033

10493 40.22 Rs.36/t

456.55

21694

Rs.2.47/1 Rs.0.32/K Wh

756.92

89.52

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

963

EFFECT ON CO2 REDUCTION OF INSTALLATION OF OUTER SKIN SURFACE TECHNOLOGIES IN HOUSES AND OFFICE BUILDINGS Tomohiko Ihara l, Takashi Handa 2, Ryuji Matsuhashi

2, Yoshikuni

Yoshida l, Hisashi Ishitani 3

l Department of Geosystem Engineering, Graduate School of Engineering, University of Tokyo, Hongo 7-3-1, Bunkyo-ku, Tokyo, 113-8656, JAPAN 2 Institute of Environmental Studies, Graduate School of Frontier Sciences, University of Tokyo, Hongo 7-3-1, Bunkyo-ku, Tokyo, 113-8656, JAPAN 3 Department of Media and Governance, Graduate School of Media and Governance, Keio University, Hiro-o 1-11-5-801, Shibuya-ku, Tokyo, 150-0012, JAPAN

ABSTRACT In this work, we evaluated the extent of reduction in CO2 emissions brought about by introducing high lightreflective and high heat-emissive paint (A) and the low light-reflective and low heat-emissive outer skin surface (B) to houses and office buildings. First, we measured the light-reflectivity and heat-emissivity of Paint A, which was 0.90 and 0.91, respectively. Next, we calculated the extent of reduction in CO2 emissions by Paint A or Surface B, using our recently developed heat load simulation program. Finally, we evaluated the economical efficiency of Paint A. For office buildings, Paint A is a reasonable measure to reduce CO2 emissions, especially when installed in cities where the heat island phenomenon occurs, or when installed in places located in low latitudes. INTRODUCTION In recent years, CO2 emissions from the commercial and residential sectors have greatly increased in Japan. Governmental regulations for energy saving are very effective for the industrial sector, but they are found to be rather ineffective for the commercial and residential sectors. Thus, low-cost measures for CO2 reduction are really required in these two sectors. In the present work, we focus upon installation of outer skin surface technologies to buildings. These technologies, low-cost measures for CO2 reduction, are applicable to buildings, which include high lightreflective and high heat-emissive paint [ 1] and the low light-reflective and the low heat-emissive outer skin surface. We calculated air-conditioning demand in the building according to our recently developed dynamic heat load simulation program, and assessed the extent of reduction in CO2 emissions brought by high lightreflective and high heat-emissive paint or low light-reflective and low heat-emissive outer skin surface. OUTER SKIN SURFACE T E C H N O L O G I E S

High light-reflective and high heat-emissive paint "High light-reflective and high heat-emissive paint" (Paint A) is one which reflects light to a greater extent (mostly as visible light rays) and emits heat to a higher extent (most is infrared ray). This was developed to mitigate the heat island phenomenon or to reduce the cooling load of a building, and is already commercially

964 available. To learn more about light-reflectivity and heat-emissivity of Paint A, we coated plywood with Paint A and examined its properties using a long-wave and short-wave radiometer (EKO MR-40) and thermocouples on the rooftop of Faculty of Engineering Bldg. 4th, University of Tokyo (Bunkyo-ku, Tokyo). Items for measurement were as follows. •

•

Short-wave incident and emitted radiation, and long-wave emitted radiation. Temperature ofradiometer's sensor, dome and plywood.

The light-reflectivity of Paint A was calculated as 0.90 and heat-emissivity was as 0.91, using the above data based on the black body radiation theory. Low light-reflective and low heat-emissive outer skin surface Low light-reflective and low heat-emissive materials are well known as selective reflecting and absorbing surfaces for solar thermal collectors and so on. In the present work, as a low light-reflective and low heatemissive outer skin surface, we used black chrome plating (Surface B), which is a representative among them.

Light-reflectivity and heat-emissivity We used the above experimental data on Paint A. The data on other outer skin surfaces were according to bibliographies. The light-reflectivity and heat-emissivity of each outer skin surface are shown in Table 1. TABLE 1 POSTULATEDLIGHT-ABSORPTIVITYAND HEAT-EMISSIVITY Outer skin surface

Absorptivity

Emissivity

Default

0.80

0.90

Default value for dynamic heat load calculation

Paint A

0.10

0.91

The present work (experiment)

Surface B

0.95

0.066

SIMULATION

Note

FOR HOUSES

Simulation conditions Under the following conditions, we performed building dynamic heat load simulation.

•

• • • •

•

An object building follows "Standard problem for house" [3] (wooden house), which the Architectural Institute of Japan (AIJ) proposed. This house is a two-story house with the area of the second floor being equal to that of the first floor (the floor area is 62.93[m2]). Refer to "Standard problem for house" for each of the schedules. The air-conditioning setting temperature ranges from 20 to 27 [deg C]. Use AIJ's "Expanded AMeDAS Weather Data" (EA Weather Data) [4], Tokyo or Naha, typical meteorological year. Naha is the most southern city among the cities in Japan. Solar position is calculated using the equations of Yamazaki [4]. Direct and diffuse solar radiations are calculated from horizontal global radiation using an Erbs model [5]. A global radiation on tilted surfaces is calculated from direct and diffuse radiation using a Perez model [6]. Earth temperature is calculated using a Hayashi model [4].

965 Results

Air-conditioning demand (Tokyo) The cooling and heating demand (heat extraction) is shown in Figure 1. 15,000 ,.--, --)

em

eElO,O00

"ID

O) ._C ¢.e-

5,000

8 0

0 Annual

Annual

Winter

Winter

Interval

(c)

(H)

(C)

(H)

(C)

Interval Summer Summer

(H)

(C)

(H)

Figure 1: Reduction in the heat extraction (Standard problem for house, Tokyo) In the case using Paint A for the outer skin surface throughout the year, the cooling demand decreased 18.8%, but the heating demand increased 10.2%. On the other hand, when using Surface B throughout the year, the cooling demand increased 11.9% and the heating demand decreased 10.6%.

C02 emissions (Tokyo) Based on the data on CO2 emissions from fuel consumption and by postulating representative airconditioners in houses (see Table 2), we evaluated the extent of reduction in CO2 emissions brought by Paint A or Surface B (see Figure 2). TABLE 2 cop OF REPRESENTATIVEAIR-CONDITIONERSANDTHEIRCO2 EMISSIONS Building

Type

COP

Fuel

[-] House Office Building

CO2 emissions intensity [kg-CO2/MJ]

Cooling

EP

0.040

Heating

EP, city gas, LPG and kerosene

0.064

Cooling

City gas

0.050

Heating

City gas

0.063

If using Paint A throughout the year, CO2 emissions increased 6%; and Paint A could not be measured. On the other hand, Surface B reduced CO2 emissions 3.2%. This result showed that heating load was larger than cooling load in houses, and that if a measure reduces heating load, it is also a measure for reducing CO2 emissions.

Switching outer skin surface The cooling and heating demands peak in the summer season (S) and winter and interval seasons (W&I), respectively. If the outer skin surface of the building can be switched for the summer and winter seasons, Paint A becomes one measure for reducing CO2 emissions. Switching the outer skin surface is not yet a practical proposition, however, it can be accomplished. For example, it is enough to cover the outer skin surface with sheets coated with Paint A during the Summer season alone.

966 With regard to the above switching technology, we evaluated the effect of Paint A only during the Summer season on the house having the default outer skin surface. In addition, we also evaluated the effect of Paint A in the Summer season alone on the house having Surface B. These simulation results are shown in Figure 2. 1,500

6 1,000 ¢/I E .9 ._~

E

m 500

c3 ¢..)

o Cooling

Heating

Total

Figure 2: Reduction in the CO2 emissions (Standard problem for house, Tokyo) Paint A alone, which is disadvantageous, can now reduce CO2 emissions 4.5%, and becomes an effective measure, when installed solely during the Summer season. A combination of Paint A and Surface B reduced CO2 emissions 10.3%. Economical efficiency as measure to reduce C02 emissions

Because Surface B is not yet commercially available, we evaluated only Paint A. In Tokyo, using it with switching is the only measure to reduce CO2 emissions. The price of Paint A is shown in Table 3. However, the switching cost is not taken into consideration. TABLE 3 THE PRICE OF OUTER SKIN SURFACE TECHNOLOGIES

Type

Cost [yen/m2]

Year [y]

Cost per year [yen/m2y]

Note

Default paint

1,830

5

403

2

Paint A

4,000

5

880

Price of material: 1,400[yen/m 2]

times painting

TABLE 4 THE CO2 EMISSIONSREDUCINGUNIT(STANDARDPROBLEMFOR HOUSE) Type

Introductory part

COa reduction [kg-CO2]

Paint A (switching)

Paint A (throughout the year)

[Tokyo]

[Naha]

Required cost [yen]

[yen/kg-CO2]

Roofs

9.0

61,300

6,800

Walls

5.7

153,000

26,600

Roofs and walls

14.8

214,000

i4,400

Roofs

16.3

38,600

2,360

Walls

10.1

98,900

9,750

Roofs and walls

26.4

138,000

5,220

Unfortunately, Paint A in Tokyo is expensive. Even in Naha, it is not always inexpensive.

967 SIMULATION FOR OFFICE BUILDINGS Simulation conditions • An object building is "Standard problem for office" which AIJ proposed. This is a reinforced concrete building which consists of one-story basement, eight stories and a tower. Its floor and total floor areas are 826.56[m 2] and 7583.44[m2], respectively. • Refer to "Standard problem for office" for each of the schedules. The air-conditioning setting temperature ranges from 22 to 26[deg C]. Results

When Paint A is applied to office buildings, it reduces CO2 emissions throughout the year, even in Tokyo. Reduction in the CO2 emissions from the office building is shown in Figure 3, and its economical efficiency is shown in Table 5.

40

,.--, O

6~ :~30 .£ "~20 t.-

8 010

o Cooling

Heating

Total

Figure 3" Reduction in the CO2 emissions (Standard problem for office, Tokyo) TABLE 5 THE CO2 EMISSIONSREDUCINGUNIT(STANDARDPROBLEMFOR OFFICE) Introductory part

Type

CO2 reduction [kg-CO2]

Required cost [yen]

[yen/kg-CO2]

Paint A (switching)

[Tokyo]

Roofs and walls

5980

2,810,000

471

Paint A (throughout the year)

[Tokyo]

Roofs and walls

98.0

2,040,000

20800

Paint A (switching)

[Naha]

Roofs and walls

10400

2,570,000

248

Paint A (throughout the year)

[Naha]

Roofs and walls

11300

1,410,000

125

In the office building in Tokyo, when switching the outer skin surface, Paint A is not so expensive. For example, photovoltaics (PV), which is also an outer skin surface technologiy, costs 73.9-418 [yen/kg-CO2]. Installation of Paint A to the office building is a reasonable measure. First, the price of Paint A will fall in the future; second, the initial cost is very low; and third, Paint A is also effective for mitigating the heat island phenomenon. Moreover, Paint A is a more reasonable measure in Naha, as PV costs 54.7-337 [yen/kg-CO2].

968 CHARACTERISTICS OF THE MEASURES TO REDUCE CO2 EMISSIONS High light-reflectivity If some buildings in cities were coated with Paint A, the streets would become dazzling. However, high light-reflectivity and shiny brightness are different things. If there is significant mirror reflection, it will have shiny brightness. However, reflection of Paint A consists not only of mirror reflections but also of diffuse reflection. For example, brightness of silver paint is greater than that of white paint, but the former reflectivity is lower than the latter one. Moreover, solar radiation contains not only visible light, but also near-infrared, and new technologies are emerging that make a particular paint to reflect only near-infrared rays. Thus, the streets would not become dazzling. Heat insulating When the building is highly heat-insulated (by heat insulating materials, ventilation layers and so on), the extent of CO2 reduction by Paint A and Surface B is smaller than that by low heat-insulated one. However, the rate of reduction in CO2 emissions from air-conditioning does not significantly alter (see Figure 4). 2,500

25

,--2,000

20

._~

-~-1,500 ¢) ¢-

.o_ ¢) ._~

O

~ 1,ooo

c3 o

10"6

500

5= •

0

0 0

25 50 100 Thickness of glass wool (24K) [mm]

150

Figure 4: Effect of heat insulating (Standard problem for office, Tokyo) CONCLUSIONS In the present work, we evaluated the extent of reduction in CO2 emissions brought about by introducing high light-reflective and high heat-emissive paint (Paint A) and a low light-reflective and low heat-emissive outer skin surface (Surface B) to houses and office buildings. Paint A and Surface B are effective in reducing CO2 emissions, especially in the case of outer skin surface switching technologies. In terms of cost for reducing CO2 emissions, installation of Paint A to houses is expensive at present. However, the costs of installation to office building are not so high, considering the initial costs. In particular, when installing to cities, Paint A will mitigate the heat island phenomenon, and when installed at locations in low latitudes, Paint A will reduce CO2 emissions further. REFERENCES 1. Kondo, Y., Nagasawa, Y. and Irimajiri, M. (2000). In: Research Reports of Society of Heating, Air-conditioning and Sanitary Engineers of Japan." Reduction of Solar Heat Gain of Building, Urban Area and Vending Machines by High Reflective paint. No. 78, pp. 15-24. (in Japanese) 2. Takizawa,H. (1985). In: The 15th Heat Symposium: Proposal of Standard problem -standard problem for office-, pp. 35-42. The ArchitecturalInstitute of Japan. (in Japanese) 3. Udagawa,M. (1985). In: The 15th Heat Symposium: Proposal of Standard problem -standard problem for house-, pp. 23-33. The ArchitecturalInstitute of Japan. (in Japanese) 4. The ArchitecturalInstitute of Japan. (2000). Expanded AMeDAS Weather Data. Maruzen. (in Japanese) 5. Erbs, D.G., Klein, S.K. and Duffle, J.A. (1982). In: Solar Energy." Estimation of the diffuse radiation fraction for hourly, daily and monthly-average global radiation, pp. 293-302. 6. Perez, R.R., Ineichen, P., Maxwell, E.L., Seals, R.D., Zelenka,A. (1992). In: ASHRAE Transactions Research Series." Dynamic Global to Direct Conversion Models, pp. 154-168.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

969

E V A L U A T I O N OF RDF P O W E R G E N E R A T I O N OF L A R G E - A R E A W A S T E T R E A T N M E N T BY LCA

Nagisa KOMATSU, Tomoko IWATA and Sohei SHIMADA Institute of Environmental Studies, Graduate School of Frontier Sciences, The University of Tokyo, Hongo, Bunkyo-ku, Tokyo 113-0033 JAPAN

ABSTRACT In this study, the viability of RDF power generation is evaluated from the viewpoint of energy saving and the reduction of CO2 emissions by analyzing operations at the Kashima RDF power plant, which has been nmning since fiscal year 2001. The purpose of this study is to consider the thermal recycling system most suitable for a given area. RDF has the advantages of being easy to transport and store and has a high calorific value. On the other hand, it has the disadvantage of requiring extra energy for manufacturing RDF itself. Kashima City, Kamisu Town and Hasaki Town run the Kashima RDF power generation operation. Although power generation and heat supply were originally planned, the latter was abandoned because of the lack of demand in this area. In this study, Kashima City and Kamisu Town are regarded as the study area since the Hasaki RDF center has not yet started operating. LCA (Inventory Analysis) is adopted as an evaluation method in this study. In the application range of LCA, not only the operating process but also the construction and dismantling processes are included. Five cases are evaluated from the viewpoint of saving energy and the reduction of CO2 emission to find the most suitable RDF power generation system. From the result of detailed analysis of each life cycle process in the present operation, it was found that the introduction of RDF power generation did not produce much advantage under present conditions. However, it was found that it would save energy and reduce CO2 emissions if it were used to produce significant electrical output by large-area waste treatment. INTRODUCTION

Recently, many efforts have made in reducing and recycling waste. A recycling-based society and the development of new recycling technologies are current goals. For the promotion of recycling, the first option must be Material Recycling. However, it is difficult to recycle some wastes, both economically and technically. Under these circumstances, it is important to promote Thermal Recycling, ie. recovering energy from waste. One promising thermal recycling method is power generation from RDF (Refuse Derived Fuel), aiming at highly efficient energy recovery by large-area waste treatment. Some studies have been done from the viewpoint of energy saving, reduction of environmental impact materials and economy [ 1]. However, the data used for these studies were estimated or supposed values, as at the time, actual power generation using RDF had not yet started in Japan. In this study, Kashima City and Kamisu Town were selected as the study area, where RDF power generation started in 2001. This is the first such operation in Japan. Previously, general waste was incinerated without any

970 heat recovery or power generation. The feasibility of the RDF power generation is evaluated considering energy savings and reduction of environmental impact materials (CO2, NOx, SOx). The optimum thermal recycling method suitable for the area is considered through the comparative study of different cases of waste treatment RDF POWER GENERATION OPERATIONS IN KASHIMA CITY AND KAMISU TOWN

In the Kashima RDF Power Generation Operation, combustible general waste collected from one city and two towns (Kashima City, Kamisu City and Hasaki Town) and industrial waste collected from industries in the Kashima Bay Industrial Area are processed into RDF in RDF Centers. RDF is combusted at the Kashima Recycling Center. Steam is produced by the combustion and used to provide heat to industries and the local community, and to generate power. It is the first operation of its kind in Japan. Power output and in-plant consumption are 3,000kW and 1,000kW, respectively. The electric power for selling to Tokyo Electric Power Co. was planned to be 2,000kW. Two RDF Centers, in Kashima City and Hasaki Town, were planned. The RDF Center in Hasaki Town started operation in April 2002. At the time of this study, the RDF Center in Kashima City and a Recycling Center in Kamisu Town are operating. Heat supply was planned, but the steam is now used only for power generation due to lack of demand for heat. The locations of centers are shown in Fig. 1. V

~

a

~ ~ ~

g

~i U "~ ",Kashima R¢cvelimzCenter

=)

)

v

) Figure 1: Locations of RDF Centers and Recycling Center ANALYSIS OF KASHIMA RDF POWER GENERATION OPERATION

Method of ProcessAnalysis LCA application range of the study area is shown in Fig.2. The construction and dismantling processes are included in this analysis. Input energies of construction processes for power generation plant and final deposit site were calculated from the relationship between construction cost and construction input energy based on the past actual data. For the RDF manufacturing plant, it was calculated from the published construction cost data. CO2 emission was calculated from the amount of material and floor area by multiplying the unit values. For the f'mal disposal site, the forest lost due to construction of the site is considered and reduced sequestrated CO2 due to lost forest are included in the calculation. For the waste collection process, the input energy and environmental impact emissions were calculated considering the distance and fuel consumption of waste collection trucks including the manufacture and eventual disposal of the vehicles. The operating process was analyzed using data on RDF manufacturing, transportation and power generation up to December 2001. The input energy and emissions were considered against the net electric power generated. Fig.

971 3 shows the input energy and emissions at the Kashima RDF Center for 1 ton transported combustible waste. The input energy required by the drying process is about 60% of the total energy required for manufacturing RDE The lower calorific value of RDF ranged between 3,750kcal/kg (15.8MJ/kg) and 3,550kcal/kg (14.9MJ/kg). In the ash transportation process, the distance between the power generation plant and the ash disposal site, and the number of tracks were included in the calculation. In the final disposal process, operations of land filling at the final disposal site were considered and the calculation was made based on the amount of ash. Dismantling costs were calculated based on the construction costs. i .............................................. t C

onstruction

P rocess

t .......................................... i

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, RDF

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aste

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~++

content

Low er cabrific

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2072kcal/kg

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,

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M o isture V o latile s o l i d vahae

4.3% 82.2% 13.6% 3672kcal/kg

Figure 3:

II E l e c t r i c i t y 90.5kW c 0 2- 29.70kg SO x 7 . 4 2 g NO x - l l . 1 4 g

h I

I1~ . . . . . . .

52.71

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] C 0 2-- 1 3 3 . 1 6 k g [ SO 3.16g NO x-- 3 1 0 . 1 9 g

Flow of RDF manufacturing process

RESULTS An inventory analysis was made for the Kashima RDF Power Generation Center using actual operation data. Although the present power generation level is not 3,000 kW, analysis was made based on the planned power generation level. According to the reports of NEDO [2] on RDF power generation planning and RDF power generation in Ohmuta City in Kyushu, the following correlation between output of power generation (y) and waste treatment capacity (x) is obtained: y = 0.0361

X2 +

38.863 x

(R 2 = 0.8987)

972

The analysis for an output of 9,200 kW, which is the maximum output obtainable at the Kashima Recycling Center (capacity 200t/day), was used for comparison. Fig. 4 - Fig. 7 show the results of input energy, CO2 emission, NOx emission and SOx emission for the incineration of conventional general waste and for RDF power generation (conventional incineration, present, 3,000kW, 9,200kW). These figures show that the power generated does not compensate for the input energy and emissions due to the small power generation under present operation. Addition of industrial combustible waste by 30% leads the input energy to zero, and addition of 50% leads CO2 emission to zero. For an output of 3,000kW, the input energy is reduced to almost zero but emissions are still greater than zero. In this case, power generation by conventional waste combustion is better than RDF power generation, as it avoids the energy consumption involved in the manufacture of RDE For an output of 9,200kW, both input energy and emissions are largely reduced. The gross thermal efficiency of RDF power generation is about 28%, which is much higher than that of power generation by combustion of general waste (= 15 - 16 %). In a relatively large operation, power generation using RDF has some advantages. But NOx emission in RDF power generation is greater than in power generation by buming general waste, for kerosene is used in the drying process in RDF power generation.

1 000.0 0.0 -500.0

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Figure 4: Input energy 120.1 ~.,n

~

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985.0

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8

Figure 6:

NOx emission

973 r

_ b.~ O ._ ~ n

,

L _

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_ilIil[...........-

i • conventbnal

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•present ~ ~

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o

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Figure 7: SOx emission OPTIMUM SYSTEM OF RDF POWER GENERATION IN THE KASHIMAAREA The comparative analysis was made using the following five cases. Case 1: RDF Center and Recycle Center at the same site (no transportation of RDF) Case 2: Conventional general waste incineration Case 3: Power generation and heat supply Case 4: Including Hasaki Town Case 5: Large-area RDF power generation (7 cities and towns ) For Case 1, the RDF transportation process is excluded. The energy required by RDF transportation is 0.5% of the total energy consumption. Therefore, the reduction of input energy and emissions is not significant. This leads to the conclusion that having some distance between the plants doesn't have much effect on the results. For Case 2, the input energy and emissions are reduced in the waste collection and construction processes with no RDF manufacturing or transportation, although they are very small. However, RDF power generation is advantageous in total owing to its power generation process. For Case 3, the specification of the steam transportation pipe was determined, based on the planned flow rate of 7t/h. Heat loss from the pipe was also calculated. The length of heat supply pipe was assumed to be 5km. As a result, the total input energy was -799.0 Meal/t-waste, CO2 emission was 138.2kg/t-waste. This shows the large effect on the reduction of input energy and emissions. RDF power generation is effective when used to supply heat, even in the case of a small operation. For Case 4 and Case 5, the results are shown in Figs. 8 - 11. In Case 5, four other cities and towns, Omigawa Town, Tosho Town, Itako City and Chosi City, located next to Kashima City, Kamisu Town and Hasaki Town, were included for the calculation of large-area waste treatment. In Case 4, a slight reduction is observed, but it is not so advantageous for introducing RDF power generation. In Case 5, the large-area waste treatment of 7 cities and towns, the input energy and environmental impact emissions were reduced greatly compared to Case 4. This implies that RDF power generation is effective in a large-area waste treatment.

630.0

1,000.0

-c.

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"~- -500.0

._m_~

. . . .

m m i n ,

,

-~

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834.7

.....

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c~andtowns D conventbnal ncheratbn

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cities and towns URDFsystem h 7 cities and towns

Figure 8: Input energy

974

• 300.0 200.0 100.0 -~

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m

mm.m~_y

, ---

,

0°.6,

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-100.0 -200.0 -300.0

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Figure 9:CO2 emission

365.4

400.0 300.0 200.0 ~o 100.0 0.0 -100.0

Itl

ll~p

mmm

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= •~

~

~

.q2~_5

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....

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pl conventi3nal iacheratbn h 7 cities and towns

..~

mRDFsystem ia 7 cities and towns

Figure 10:

NOx emission =A n

,Itl

,--,-'.-,

mm m

....

.

.

,q6_4

n m,r'--~,mm-'i-,~ mm

• conventbnal iaciaeratbn ia 3 city and towns IIIRDFsystem ia 3 city and towns

15-9..~

..

.

=o F

[] conventbnal i a c i a e m t b n ia 7 cities and towns mlRDFsystem in 7 cities and towns

Figure 11: SOx emission CONCLUSIONS The main results obtained by this study are summarized as follows; 1. Consumption of energy in the manufacturing of RDF must be compensated for by the power generated by the RDE In small power plants, heat supply should be incorporated. The introduction of RDF power generation is effective if heat is also supplied, even when the electrical output is small. 2. Except in the case of large-area waste treatment with large electrical output, RDF is not a suitable power generation system because of the low thermal efficiency of power generation. 3. The input energy for transportation is very small compared to that required by construction. It is better to construct a small number of RDF power generation plants that can operate on a large scale. ACKOWLEDGEMENTS The authors express their thanks to Kashima City and Kamisu Town for the supply of data for this study. REFERENCES 1. Nagata,K. and Ureshino M. :Availability ofRDF- from viewpoint of LCA-, (1996)J. WasteManagementResearch, 7, 282 2. Ishikawa Pref. :Study on RDF power generation by general waste in Noto Area, (1998), NEDO Report

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

975

CONTRIBUTING TO REDUCTION OF CO2 EMISSIONS THROUGH DEVELOPMENT OF A HEAT-INTEGRATED DISTILLATION COLUMN M. Nakaiwa I, K. Huang l, T. Endo 1, T. Ohmori l, T. Akiya I, T. Takamatsu 2, S. Beggs 3 and C. Pritchard 3 1National Institute of Advanced Industrial Science and Technology (AIST), Tsukuba 305-8565, Japan ZInstitute of Industrial Technology, Kansai University, Suita 564-8680, Japan 3School of Chemical Engineering, University of Edinburgh, EH9 3JK, UK

ABSTRACT This paper introduces the development of a heat-integrated distillation column as a means of contributing to the reduction of CO2 emissions. The process has evolved from the application of the heat-pump principle to a distillation process, leading to an internal heat integration between the whole rectifying and the whole stripping sections. Three candidate configurations have been proposed and analyzed for the practical process realization. The results from the operation of the first bench-scale plant and simulation studies demonstrate its substantial contribution to the reduction of CO2 emissions.

INTRODUCTION The imperatives of global wanning and sustainable development demand efficient energy utilization in all aspects of life. The chemical processing industry, as an intensive energy consumer, is a major contributor to CO2 emissions. It accounts for 25% of the energy consumed by industries overall, while the distillation process accounts for up to 50% of the energy consumed by this industry. To abate its impacts and achieve the targets designated by the Kyoto Protocol, the development of energy-efficient distillation processes has a potentially very important role. An energy-efficient heat-integrated distillation column (HIDiC) is developed in this work as a way to alleviate C02 emissions. Three candidate configurations have been proposed and analyzed for the practical process realization. The results of the first bench-scale plant experimentation of its kind and simulation studies are given in detail and its effectiveness in mitigating C02 emissions is discussed.

THE C O N C E P T U A L C O N F I G U R A T I O N OF THE HIDiC In Figure 1, a conceptual configuration for the HIDiC has been created. The column's stripping and rectifying sections are separated, but connected through internal heat exchangers. To accomplish internal heat transfer from the rectifying section to the stripping section, the rectifying section is operated at sufficiently higher pressure than the stripping section to give higher temperatures throughout its length. To adjust the pressures, a compressor and a throttling valve are installed between the two sections. Owing to the heat integration, a proportion of the latent heat transported in the rectifying section is transferred to the stripping section, thereby generating both the reflux flow for the rectifying section and the vapor flow for the stripping section. Thus the condenser and reboiler are, in principle, not needed; and operation at zero external reflux is theoretically

976 possible. Figure 2 elaborates the principle of the HIDiC. The heat discharged along the rectifying section has been upgraded through a compressor and reused along the stripping section. By this internal heat integration, process energy efficiency can be improved, substantially. Compressor

F, zf

Throttling valve Figure 1: A schematic representation of a HIDiC

TI

Reboiler

Reboiler duty .," ~ ~ e b c

°.°o°.°°.o°°°°°°° emperature I..] difference

m t e g r ~ l ~1,. a

thenat

~Mirror image-'] " ] ofrectifymg1 [section curve.) Condenser H Figure 2: The principle of the HIDiC in a T-H diagram

ALTERNATIVES FOR THE PRACTICAL REALIZATION OF HIDiC Although the HIDiC appears to be very attractive in energy efficiency, it poses great difficulties in realizing an effective configuration. Difficulties arise from not only the arrangement of sufficient heat transfer area between the rectifying section and the stripping section, but also from the possible degradation in mass transfer between vapor and liquid phases. Three potential configurations are introduced, below. A Concentric Configuration

A concentric configuration is very similar, in structure, to a multi-tube and multi-shell heat exchanger (cf. Figure 5). Both tube side and shell side are equipped with mass-transferring packing and are operated respectively as the rectifying and the stripping sections [ 1,2].

977

A Configuration with Heat Transfer Loops The intemal heat integration is carried out by pumping a liquid heat transfer medium around a single or multiple heat transfer loops (Figure 3 shows heat integration through a single heat-transferring loop). This method can effect internal heat integration on each plate in both sections [3].

RECTIFYING STRIPPING SECTION Tm,g~0) -- Tin(top)= Tm,s(0)

1

Tm,r( )

'(

' ~

+ Tm,s(1) 1

Tm,r(3)

~

+ Tm,s(3) Tm,s(ns-3) Tm,r(nr-2) Tm,s(ns-2)/~

Tm,r(nr-1)

+ Tm,s(ns-1) >

Tm,r(nO= Tm(bot) = Tm,s ( n s ) ~ ---] ~ Figure 3: A potential configuration with a heat transfer loop

A Configuration with Heat Pipes Internal heat integration is carried out by a series of heat pipes linking pairs of plates in the rectifying and the stripping sections (Figure 4). The high internal heat transfer coefficients and negligible temperature drop along the heat pipes permit effective heat transfer over small temperature differences [3].

STRIPPINGSECTION

RECTIFYINGSECTION

PLATE

HEATPIPEn

~l 0 oleT"piatl°n ~

o

!° ! ooo?ool, c°ndoenS~_i°n

Tm(n)

Figure 4: A potential configuration with heat pipes

PLATEn

978

I ~ I Throttling~~ I ' 'Va~e T I

I

1 I~

Top Product

~~ri--6.1C_°m

I

i

~r~o~f---~

.

.

.

.

press°r

.

.

.

.

Figure 5: Layout for the bench-scale plant E X P E R I M E N T A L EVALUATIONS CARRIED OUT ON THE BENCH-SCALE PLANT

Layout of the Bench-Scale Plant As shown in Figure 5, the plant is about 27 m in height and 0.254 m in diameter. Packing has been furnished in both sections and the internal design guarantees sufficient contact between vapor and liquid phases, effecting a major improvement in performance over that of conventional packed distillation columns.

Process Startup An inverse heat transfer (i.e., heat transfer from the stripping to the rectifying section) must be avoided during process startup. To enhance the pressure difference as quickly as possible, one needs to start the overhead trim-condenser later than the bottom trim-reboiler. It was found that no special difficulties were encountered during startup. Around 10 hours were needed for the process to reach its normal steady state, although a substantial reduction of this time period should be possible through appropriate use of the trim heat exchangers. Steady State Operation with and without External Reflux Steady state operation with external reflux was obtained directly after startup. More than 100 hrs of continuous operation have been performed and no special difficulties were encountered during the experimental tests. The results obtained show that the process can be operated very smoothly, just as conventional distillation processes. External reflux-free operation was achieved by reducing the external reflux rate whilst gradually increasing the pressure difference (Pr-Ps) between the rectifying and the stripping sections. As can be seen, the operation of the bench-scale plant could be easily shifted to the reflux-free mode after the startup period (Figure 6a). In this case the internal heat integration between the rectifying and the stripping sections functions as an efficient means of generating internal liquid and vapor flows (Figure 6b). Figure 6c illustrates the time history of the overhead and bottom temperatures in the rectifying and the stripping sections respectively, demonstrating stable operation of the bench-scale plant. Figure 7 shows the steady state heat and mass balances for the bench-scale plant. It can be readily seen that the internal heat integration between the rectifying and the stripping sections plays a very important role in the process operation. 100

4.0

80 ~"~P =060

k_

~ 3.0

Fe~l

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Figure 6: A typical reflux-free operation result of the bench-scale plant

979

I ~°°c .~15.3 kwI 890C 3.28kmol/h Benzene 59.2mo1%

'.~li~R = 0 II' | ~ 1.94kmol/h i I I Benzene 99.9mo1% ~1 I 114.7kW> 8 ~/I I Heat radiation / 73 kmol/h

I.J~l ~kwl

121.3kW1 2.34kmol/h

w--i ,~Compressor 0ower

--.. | -"117°C 2.79 kmol/h 1.34 kmol/h Toluene 99.7 mol% Figure 7: Heat and mass balances for the bench-scale plant

Energy Efficiency of the HIDiC Table 1 compares the operating costs between the experimental HIDiC and a conventional distillation column designed for the same separation task. As can be seen, the HIDiC is about 40 % more energy efficient than the conventional distillation column [4]. This saving is, however, lower than that calculated in the conceptual process design [5], mainly due to the fact that the bottom trim-reboiler is still in operation and a compressor with much low an isentropic efficiency ( 09

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Capacity (MW)

(a) capital cost (b) conversion efficiency Figurel" Results of the literature survey on capital costs and efficiencies of power plants

TREND OF CAPTAL COSTS

Natural Gas Combined Cycle (NGCC) At present, NGCC is the cheapest option for electricity production, when one compares its relatively low greenhouse gas emissions in relation to other fossil fuel power plants. Due to price wars for larger NGCC plants, the capital costs of NGCC decreased rapidly in 1990's. As shown in Figure 1, the capital cost of NGCC in US$/kW decreases in line with increasing capacity, and is lower than other power plants [1-6]. Some NGCCs with higher capital costs are equipped with a CO2 capture technology. In many studies, the capital costs of NGCC including CO2 capture are estimated to be 2 to 3 times higher than ones without CO2 capture, though they might still be cheaper than IGCC or PC without CO2 capture [2-6]. A study of historical capital cost reductions of NGCC using leaming curves shows a progress ratio of 75% during the 1990's, indicating that capital costs declined by 25% for each doubling of cumulative installed capacity [7]. During this period, the increase of turbine input temperature has reached 1430°C and a more integrated steam cycle with a triple pressure system has been applied. With the exception of very small-scaled plants, the thermal efficiency is more than 50% and reached up to 60% on the latest models. Since NGCC can be considered a mature technology, it might be difficult to expect further significant improvements in the medium run (around 2030). Therefore, the progress ratio of NGCC might increase to around 90%, indicating a capital cost decline by only 10% for each doubling of cumulative installed capacity.

Proton Exchange Membrane Fuel Cells (PEFC) FC is a demand-side technology with a much smaller capacity than NGCC. A variety of fuel cells with different electrolytes, i.e., PAFC, MCFC, SOFC and PEFC, are presently in different stages of development. The capital costs of all types of FCs are generally high, and vary widely independently of the capacity [8-15].

989 Over the past few years, there have been intense efforts to develop low-cost PEFC systems. While the primary emphasis has been on automotive applications, an equally important application may be combined heat and power generation in commercial and residential buildings. In the medium run, there could be more potential for reducing the capital costs of PEFC than NGCC. In the automotive applications, the cell stack costs must achieve stringent cost goals of perhaps 50 US$/kW. A recent study regarding PEFCs for automotive application, which utilized a learning curve, concluded that the unit cost can be reduced to 38 US$/kW with the progress ratio of around 80%, assuming an increase of the cumulative number of fuel cell vehicles to 5,000,000 until 2020 [8]. In addition, the technical challenges are in many respects less severe for stationary applications than for automotives, although longer lifetime is required for the stationery application. Therefore, in a recent study, which estimates the capital costs of stationary PEFC with high volume manufacturing, 10,000 units/year, around 300 US$/kW (for a unit size of a few 10 kW) [9]. This figure is also used in the analysis presented below. CALCULATION BASIS PEFC Fueled with Hydrogen In the initial phase of a "hydrogen economy", hydrogen could be produced from currently available competitive fossil fuels. At a later stage, as the market develops, the production system could evolve towards renewable resources, such as biomass. This report assumes that PEFC is fueled with natural gas or hydrogen, where hydrogen is produced either by steam methane reforming (SMR) or biomass gasification. Based on the literature [ 10] including detailed techno-economic analysis of PEFC for residential use, this report assumes for PEFC without reformer 50% lower capital costs and 33% higher efficiencies than for PEFC with reformers. Greenhouse Gas Emissions In terms of total greenhouse gas emissions of electricity production, it is important to account the total emissions of the fuel cycle. In order to calculate the greenhouse gas emissions on a fuel-cycle basis, this paper used the value from the GREET model, which was developed for the evaluation of energy and emission impacts of vehicle technologies by Argonne National Laboratory [ 16-17]. In the GREET model, emissions of CO2, CH4 and N20 are considered at 3 stages, i.e., feedstock recovery, fuel production and final operation. The greenhouse gas emissions from biomass-based hydrogen production were assumed to be fully recovered during the biomass growing cycle. Thus, no greenhouse gas emissions from hydrogen at the final operation stage were assumed.

Cost The costs of generating electricity depend not only on the capital costs, but also on fuel costs, O&M costs, efficiency, and capacity factors, etc. In this study, the cost of electricity (COE) is based upon capital costs and efficiency taken from the literature, and constant values of the other factors. In order to discuss the influence of fuel price differences between supply side and demand side on the COE of PEFCs, the installation of PEFCs on both sides is considered. The assumptions used are described below: Fuel cost O&M cost Capacity factor Discount rate Lifetime

Natural gas: 3.0 US$/GJ (supply side), 6.0 US$/GJ (demand side) Biomass: 5.0 US$/GJ Coal: 1.5 US$/GJ NGCC: 2 mills/kWh, NGCC with COz capture: 4 mills/kWh, PEFC: 3 mills/kWh NGCC: 80%, PEFC: 80% 10% NGCC: 30 years, PEFC: 15 years

The hydrogen production cost was estimated based on the capital costs of hydrogen production systems shown in Figure 2 [18-28]. As for biomass gasification, some different designs of gasifiers are reported. In this assessment, an indirectly heated gasifier developed at the Battelle Columbus Laboratories (BCL) was selected as the representative technology. This biomass gasification technology is not commercialized yet, but it has been estimated to be the cheapest hydrogen source of all biomass gasification options. Considering

990 hydrogen transportation costs of 3 US$/GJ and a production capacity of 1 million Nm3/day (12,800 GJ/day), this report assumes hydrogen costs as follows [29]. SMR: 7 US$/GJ (supply side) BCL: 11 US$/GJ (supply side)

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E L E C T R I C I T Y GENERATION COSTS AND GREENHOUSE GAS EMISSIONS Figure 3 shows COE and greenhouse gas emissions of NGCC and PEFC. Because of the high cost of natural gas on the demand side and relatively lower efficiency, both the COE and greenhouse gas emissions of PEFC fueled with natural gas is still higher than the NGCC without CO2 capture, even if the capital cost of PEFC is reduced to 300 US$/kW by mass production. The COE and greenhouse gas emissions are much higher in the PEFC fueled with hydrogen produced by SMR. Even if the relative low fuel price on the supply side is used, the COE of PEFC is higher than the one of NGCC. Therefore, PEFC must be utilized as a co-generation system for reducing greenhouse gas emissions in comparison to NGCC. In other words, if PEFC producing only electricity is installed at a large-scale due to the lowered capital cost instead of NGCC in the future, greenhouse emissions might increase. If biomass-based hydrogen is used in PEFC, we can assume that emissions are emitted only at the biomass plantation and transportation stages, resulting in very low emissions, though the COE of PEFC fueled with biomass-based hydrogen would be quite high, more than 0.1 US$/kWh. The COE of NGCC without CO2 capture could be smaller than that of NGCC with CO2 capture unless the carbon tax of 300 US$/t-C is applied. NGCC w/o CO2 cap. [] FC (natural gas)

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side

991 GREENHOUSE GAS REDUCTION COST Figure 4 shows the relationship between the emissions reductions and the reduction costs (CoHo) relative to a conventional coal power plant with 0.039 US$/kWh and 850 kg-CO2/kWh. Because of the low COE, CoHo of NGCC without CO2 capture is negative. NGCC without CO2 capture might be the most cost-effective option for reducing greenhouse gases among electricity production technologies fueled with natural gas. CoHo of NGCC with CO2 capture is still lower than that ofPEFC. Ifa very high carbon tax is applied, the NGCC with CO2 capture and then the PEFC fueled with biomass-based hydrogen could also be cost-effective for reducing emissions. However, PEFC fueled with natural gas or natural gas-based hydrogen might not be a costeffective option unless it is utilized as a co-generation system to reduce the emissions from boilers for hot water supply. ! O NGCC w/o CO2 cap. [] FC (natural gas)

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(b) PEFC supply side (a) PEFC demand side Figure 4: Greenhouse gas reduction costs relative to a conventional coal power plant

CONCLUSIONS By analysing data from the updated CO2DB, this report discussed the cost-effectiveness of NGCC and PEFC technologies in reducing greenhouse gases. The emissions reduction costs of PEFC might be higher than the ones of NGCC, even if the mass production of PEFC considerably reduces its capital costs. Therefore, PEFC should be used as a co-generation system for reducing greenhouse gas emissions in a cost-effective way. In the medium run, NGCC without CO2 capture might be the most cost-effective technology among electricity production technologies fueled with natural gas. REFERENCES Gas Turbine World 2000-2001 Handbook (2000) Vol.21, Pequot Publishing David, J., and Herzog, H. (2000) The Cost of Carbon Capture. Proc. of the Fifth International Conference on Greenhouse Gas Control Technologies (GHGT-5), pp.985-990 Audus, H. (2000) Leading Options for the Capture of CO2 at Power Stations, 5th International Conference on Greenhouse Gas Control Technologies (GHGT-5), pp.91-96 Undrum, H., Bolland, O., and Aarebort, E. (2000) Economical Assessment of Natural Gas Fired Combined Cycle Power Plant with CO2 Capture and Sequestration, 5th Intemational Conference on Greenhouse Gas Control Technologies (GHGT-5), pp.167-172 Herzog, H., and Vukmirovic, N. (1999) CO2 Sequestration : Opportunities and Challenges, 7th Clean Coal Technology Conference Delallo, M., Buchanan, T., White, J., Holt, N., and Wolk, R. (2000) Evaluation of Innovative Fossil

992

10. 11. 12. 13. 14. 15.

16. 17. 18.

19. 20. 21. 22. 23. 24.

25.

26.

27. 28. 29.

Cycles Incorporating CO2 Removal, Proc. of 2000 Gasification Technologies Conference Colpier, U.C., and Comland, D. (2002) The Economics of the Combined Cycle Gas Turbine - An Experience Curve Analysis, Energy Policy 30, pp.309-316 Tsuchiya, H., and Kobayashi, O. (2002) Fuel Cell Cost Study by Learning Curve, presented at International Energy Workshop 2002. available at Kreutz, T., and Ogden, J. (2000) Assessment of Hydrogen-Fueled Proton Exchange Membrane Fuel Cells for Distributed Generation and Cogeneration. Proc. of the 2000 U.S. DOE Hydrogen Program Review, pp.785-827. Thomas, C.E., James, B.D., and Lomax, F.D. (2000) Analysis of Residential Fuel Cell System & PNGV Fuel Cell Vehicles. Proc. of the 2000 U.S. DOE Hydrogen Program Review, pp.756-784. Schaeffer, G.J. (1998) Fuel Cells for the Future. University of Twente, (ISBN 90 365 12 30 1). Brown, D. R. and Jones, R., (1999) An Overview of Stationary Fuel Cell Technology, Report PNNL12147 prepared for the U.S. Army Forces Command (FORSCOM), DE-AC06-76RLO 1830. Ernst, W.D., Law, J., Chen, J., and Acker, W. (1998) PEM Fuel Cell Power Systems for Automotive Applications: Technology and Implementation. Paper presented at the Fuel Cell Seminar 1998 Bloomfield, D., and Bloomfield, V. (1998) Residential Power Generator. Paper presented at the Fuel Cell Seminar 1998 Iannucii, J., Eyer, J., and Horgan, S. (1999) Economic Market Potential Evaluation for Hydrogen Fueled Distributed Generation and Storage, Proc. of the 1999 U.S DOE Hydrogen Program Review, NREL/CP-570-26938 Wang, M.Q. (1999) GREET 1.5 - Transportation Fuel-Cycle Model Volume 1: Methodology, Development, Use, and Results, ANL/ESD-39, Vol.1 Wang, M.Q., Saricks, C., and Santini, D. (1999) Effects of Fuel Ethanol Use on Fuel-Cycle Energy and Greenhouse Gas Emissions, ANL/ESD-38. Mann, M., K. (1995) Technical and Economic Assessment of Producing Hydrogen by Reforming Syngas from the Battelle Indirectly Heated Biomass Gasifier, Report NREL/TP-431-8143, NREL/DOE. Williams,.R.H. (1998) Fuel Decarbonization for Fuel Cell Applications and Sequestration of the separated CO2. Spath, P.L., and Mann, M.K. (1998) Technoeconomic assessment of four biomass-to hydrogen conversion technologies. Proceedings of the 12th World Hydrogen Energy Conference Amos, W., (1998) Analysis of Two Biomass Gasification/Fuel Cell Scenarios for Small-Scale Power Generation, NREL/TP-570-25106 Basye, L., and Swaminathan, S. (1997) Hydrogen Production Costs - A Survey SENTECH, Inc. Report DOE/GO/10170-778, US Department of Energy, Maryland, US. Wurster, R., and Zittel, W. (1994) Hydrogen Energy, published at the workshop on Energy technologies to reduce CO2 emissions in Europe: prospects, competition, synergy. NEDO (New Energy and Industrial Technology Development Organization) (1999) Conceptual design of the total system. World Energy Network (WE-NET) Project Annual Report, Subtask 3: Tokyo, Japan. Written in Japanese. Williams, R.H. (1998) Fuel decarbonization for fuel cell applications and sequestration of the separated CO2. In Ecorestructuring: Implications for Sustainable Development. R.U. Ayres, P.M. Weaver (eds.), United Nations University Press, Tokyo, pp. 180-222. Blok, K., Williams, R.H., Katofsky, R.E., and Hendriks, C.A. (1997) Hydrogen Production From Natural Gas Sequestration of Recovered CO2 in Depleted Gas Wells And Enhanced Natural Gas Recovery, Energy 22(2/3), pp.161-168. Berry, G. D. (1996) Hydrogen as a Transportation Fuel: Costs and Benefits, Report UCRL-ID123465, Lawrence Livermore National Laboratory, University of California, California, US. Ogden, J. (1999) Hydrogen Energy System Studies. Report NREL/TP-570-26938, National Renewable Energy Laboratory, US Department of Energy, Colorado, U.S. Makihira, A., Barreto, L., and Riahi, K. (2002) Assessment of Alternative Hydrogen Pathways: Natural Gas and Biomass, ILASA (International Institute for Applied Systems Analysis), Final Report on the TEPCO-IIASA Collaborative Study.

ENERGY E F F I C I E N C Y INDUSTRY

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

995

THE C E M E N T INDUSTRY AND GLOBAL C L I M A T E CHANGE: C U R R E N T AND POTENTIAL FUTURE C E M E N T I N D U S T R Y CO2 EMISSIONS Natesan Mahasenan l, Steve Smith 2 and Kenneth Humphreys l IPacific Northwest National Laboratory - Battelle, Richland, WA 99352, USA. 2joint Global Change Research Institute, Pacific Northwest National Laboratory- Battelle - University of Maryland, College Park, MD 20740, USA.

ABSTRACT

The cement industry is responsible for approximately 5% of global anthropogenic carbon dioxide emissions. Atmospheric concentrations of greenhouse gases cannot be stabilized without addressing this important emissions source. The industry emits nearly 900 kg of CO2 for every 1000 kg of cement produced. As a result of the significant emissions per unit of cement produced, emerging climate change policies have the potential to place the industry at significant financial risk. To create the foundation for an industry-wide climate change response strategy and manage the associated environmental and financial risk, ten of the world's largest cement companies, under the auspices of the World Business Council for Sustainable Development, sponsored a quantitative assessment of current and potential future CO2 emissions from the cement industry in 14 regions of the world [1 ]. Some key results from the assessment are reported in this paper. Quantitatively, current and potential future cement industry greenhouse gas emissions are evaluated under the new family of Intergovemmental Panel on Climate Change (IPCC) scenarios that were developed as part of the Third Assessment and documented in the Special Report on Emissions Scenarios (SRES). The results of the assessment show that if the industry does not improve its current specific emissions (i.e., kg of CO2 emitted per unit of cement produced), its relative contribution to anthropogenic CO2 emissions increases by more than one order of magnitude over the next century. The industry faces several challenges as it seeks to reduce its specific CO2 emissions, including (1) its heavy dependence on fossil fuels, and especially highcarbon fossil fuels, (2) its dependence on limestone-based clinker, and (3) the age and efficiency of its capital stock, especially in regions where future demand is expected to be high.

INTRODUCTION

The cement industry is responsible for approximately 5% of the global anthropogenic CO2 emissions (based on data from [2,3,4,5,6]). Cement-related greenhouse gas emissions come from fossil fuel combustion at cement manufacturing operations (about 40% of the industry's emissions); transport of raw materials (about 5%); and combustion of fossil fuel required to produce the electricity consumed by cement manufacturing operations (about 5%). The remaining cement-related emissions (about 50%) originate from the process that converts limestone (CaCO3) to calcium oxide (CaO), the primary precursor to cement, as shown in Eqn. 1: CaCO

3 --), C a O + C O z

(1)

996 As shown by Eqn. 1, it is chemically impossible to convert limestone (CaCO3) to CaD and then cement clinker without generating CO2, which is currently emitted to the atmosphere. Table 1, based on data from [3,4,5,6], presents the total estimated emissions, cement demand, unit emissions, energy intensity and clinker factor (kg of clinker per kg of cement) in 2000 for the global cement industry. As shown, the gross unit-based emissions for the industry were approximately 0.87 kg CO2 per kg of cement. Unit-based emissions vary globally from 0.73 to 0.99 kg CO2 per kg of cement. There is similar variation in energy intensity and clinker factor. Two of the important factors that drive unit-based CO2 emissions are the energy intensity and clinker factor. Lowering the energy intensity lowers the fossil fuel combustion during production. Lowering the clinker factor directly reduces both the process emissions and the associated fuel-related emissions, as shown in Eqn. 1. Other options for reducing unit CO2 emissions are switching to fuels with lower carbon content, or using fuels that qualify for an emissions credit. TABLE 1 CEMENT DEMAND, TOTAL AND UNIT CO2 EMISSIONS, ENERGY INTENSITY AND CLINKER FACTOR IN MAJOR WORLD REGIONS FOR THE YEAR 2000

Region

Total C02 Emissions (Mt/year)

Total Cement Demand (Mt/Year)

UnitEmissions (Mt CO2 / Mt Cement)

Energy Intensity (MJ/Kg Cement)

90

90

186 60

220 82

449 112 " 40 64

500 123 44 69 88 37 134 87 80 1571

0.99 0.91 0.84 0.73 0.79 0.90 0.92 0.90 0.93 0.81 0.89 0.82 0.85 0.85 0.87

5.50 5.20 4.04 3.10 4.08 4.71 4.65 4.05 4.71 5.52 5.20 4.48 4.75 4.92 -

1. USA 2. Canada 3. W. Europe 4. Japan 5. Aus. & NZ 6. China 7. SE. Asia 8. Rep. of Korea 9. India 10. FSU 11. Other E. Europe 12. S. & L. America 13. Africa 14. Middle East TOTAL

THE EMISSIONS REDUCTION

109 74 68 1371

Clinker Factor (Kg/Kg)

0.88 0.88 0.81 0.80 0.84 0.83 0.91 0.96 0.89 0.83 0.83 0.84 0.87 0.89

CHALLENGE

Historically, the cement industry as a whole has made only modest gains in lowering energy intensity and the clinker factor over the last decade or so, though some regions have done better [1 ]. In order to understand the magnitude of the challenge facing the cement industry, we need to understand the implications of no-action by the cement industry against future trends in worldwide emissions. Future human social, economic, and technological development cannot be predicted with a high level of certainty. Therefore, in looking at the future over long time horizons, it is helpful to examine a number of plausible future scenarios. We use the scenarios developed by the Special Report on Emissions Scenarios [7], under the auspices of the Intergovernmental Panel on Climate Change (IPCC). The IPCC SRES scenarios are grouped into 4 families, each with a set unique set of economic, demographic, technology and energy-use assumptions. These scenarios are termed A1, A2, B 1 and B2, and are described in detail in [7].

Understanding Cement Demand In order to compare future cement emissions against these baselines, it is necessary to develop a predictive equation for future cement demand. Two obvious candidates for the predictive variables are population and gross domestic product, or GDP. Historical cement demand [4,5] was compared with GDP and population data for the 14 regions shown in Table 1 for a sub-interval of at least 20 years between (1947-1997). To ensure a consistent comparison across the different regions, the GDP values were adjusted for purchasing

997

power parity (PPP). When the cement data in per capita terms are evaluated, a consistent pattern emerges. In "developed" economies (USA, Canada, Japan, Australia & New Zealand, and Western Europe), the cement demand 'flattens' out when per capita GDP is approximately US$8000 (expressed in 1990 dollars). This is consistent with the literature [8]. Representative plots for Japan and Western Europe are shown in Figure 1.

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Figure 1. Per Capita Cement Demand vs. Per Capita GDP for Western Europe and Japan In China, Korea, India, Latin and South America, and other developing regions, where per capita GDP has not yet reached US$8000, the per capita cement demand is a linearly increasing function of the per capita GDP. Representative plots for China and India are shown in Figure 2. 300

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Figure 2. Per Capita Cement Demand vs. Per Capita GDP for China and India

Based on this remarkably consistent observation across all regions, it was postulated that cement demand is proportional to the GDP at lower income levels (< US$8000, deflated to 1990), while at higher income levels, it is proportional to the population. The function form shown in Eqn. 2 can therefore represent cement demand, when GDP and population are known. A X -'r + B X r Demand

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998 From the above equation, it can be readily seen that at low incomes (X is small), the relationship reduces to simply A (=a*GDP), and at high X, it reduces to B (=[3*population). In order to test the above functional form, tx and 13were estimated for each region based on historical values for cement demand, GDP and population, ot is estimated when per capita GDP is below US$8000, and [3 is estimated once per capita income exceeds that threshold. In developing regions, where per-capita incomes are less than US$8000, [3 values are assigned based on values in developed parts of the world. After a and [3 were determined in this way, historical GDP and population data were used to predict historical cement demand and compared against the actual numbers. Excellent fit and r: values generally in excess of 0.95 were obtained for all regions for '{=3. A comparison of the actual cement demand per capita and the predicted cement demand per capita for selected regions is shown in Figure 3. 800

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Projecting Future Cement Demand Based on the GDP and population data for the four IPCC SRES scenarios [7], we can now project cement demand into the 21 st century. Projected cement demand over the next century is shown in Figure 4. The global demand projections for the four scenarios highlight the nature of the challenge for the industry: while the demand projections are closely bunched together until about 2020 or so (about 30% difference between the extreme scenarios), the gap widens to a factor of four by the end of the next century. Thus, it is imperative that whatever strategy the industry chooses to meet its 2020 goals must be sufficient to handle the longer-term growth in cement demand. The spatial distribution of the demand is also important. In all four scenarios, the highest demand and the fastest growth are in Asia, followed by Africa and the Middle East, where demand increases quite rapidly after 2020. Latin/South America and Eastern Europe show modest increases in cement demand over the next half-century, while it is relatively flat in Western Europe and North America. These trends are keeping with the historical relationship between per capita incomes, population and cement demand. The regions that have rapidly growing economies and/or populations are predicted to show proportionally large increases in the demand for cement, while relatively prosperous regions with slower population growth show much lower demand growth rates. There may also be cultural and societal factors driving the cement demand in different parts of the world-- for example, multi-family housing, which is popular in areas with high population densities (and relatively lower incomes), is much more cement and concrete intensive than single-family housing that may be found in areas with lower population densities and/or higher income levels.

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Figure 4. Projected Cement Demand under IPCC SRES Scenarios

As the cement industry makes progress on the issue of climate change, it will be necessary for the industry and individual companies to set emission mitigation goals. While there are a multitude of possible goals, it is suggested here that one plausible goal is for the industry to commit itself to participating in a global effort that includes a peak in global emissions, followed by an indefinite decline in emissions until stabilization of atmospheric concentrations of greenhouse gases is achieved. For the purposes of understanding the possible implications for the industry of adopting such a goal, this paper assumes that 1) the industry makes this commitment and 2) further commits to not allowing the industry's relative contribution to global emissions (-5%) to exceed this level. That is, in the near-term while global emissions from all sources continue to grow, they would grow at a pace equal to or less than this growth. In the medium- to long-term when global emissions are declining, cement industry emissions would decline at an equal or greater pace. This would put the cement industry in a leadership position on the long road to addressing climate change and creating a more sustainable industrial system. Under this type of mitigation regime, Table 2 provides the projected cement demand, cement-related CO2 emissions under No-Action, target CO2 emissions and the improvement in unit emissions that would be required to meet the target.

TABLE 2 PROJECTED CEMENT DEMAND, CO2 EMISSIONS AND IMPROVEMENT REQUIRED

Scenario ~ Cement Demand (Mt) No-Action Cement Emissions (Mt CO2) Share of Global CO2 Emissions Target Emissions (Mt CO2) Implied Improvement in Unit Emissions from No-Action Case Cement Demand (Mt) No-Action Cement Emissions (Mt CO2) Share of Global C O 2 Emissions Target Emissions (Mt CO2) Implied Improvement in Unit Emissions from No-Action Case

A1B 3221 2675 7% 1841

A2 2656 2190 6% 1816

BI 2483 2054 7% 1464

B2 2855 2378 7% 1560

31%

17%

29%

34%

5488 4604 8% 2848

5086 4241 7% 3017

3766 3153 8% 1881

5067 4766 9% 1949

38%

29%

40%

59%

The results suggest that if the cement industry chooses to minimize its financial risk and adopt a leadership position on this issue, a productive goal would be for the industry to commit itself to a reduction in unitbased emissions of 30% by 2020 (based on the range of possible required reductions, 17% to 34% in Table

1000 2, associated with a range of possible future scenarios). Meeting such a goal would require that the industry implement significant mitigation measures in the short-term. At the same time, the results suggest that the cement industry must work to develop new technology and new cementituous products that will enable larger reductions by 2050 (by up to an additional 30%) when global cement demand potentially increases dramatically and climate change policies also tighten. CONCLUSIONS The cement industry is faced with potentially explosive demand for its product over the next few decades. Across the four scenarios examined here, global cement demand is projected to increase 60% to 105% over current levels by 2020. By 2050, three of the four scenarios have approximately equivalent cement demand, with an approximately-225% increase from current levels. Most of the increase in demand is in developing regions of the world, where the industry's current capital stock is relatively old and inefficient. While 2050 may seem far into the future, nearly all cement plants built in the coming decade or two to meet this demand will still be operating at this point in time. Thus, the decisions the industry makes today to meet this significant emissions mitigation challenge will affect its future well beyond 2020. The cement industry therefore needs to adopt a two-pronged strategy for responding to this challenge. First, companies must progressively pursue cost-effective CO2 reductions by (1) expanding sales of cement with lower clinker content (e.g., composite cement with fly ash or blast furnace slag), (2) increasing the use of alternative fuels (bio-based, low-carbon, or waste fuels that provide a net carbon dioxide emissions reduction), and (3) initiating energy efficiency enhancements (improving equipment and phasing out inefficient plants). Second, to enable additional, long-term, cost-effective CO2 reductions, the cement industry must undertake or support R&D at a much higher level than today. This R&D must be focused on the development of highly innovative low-CO2 products and processes, as well as low-CO2 business ventures. Examples of such ventures might include capturing and sequestering CO2, co-producing electricity and cement in lowCO2 facilities, or earning royalty income from low-CO2 processes or products licensed to other companies. Without a commitment to long-term innovation, the industry will likely find itself facing growing emission liabilities as individual nations commit themselves to ever-tighter CO2 constraints in an attempt to stabilize atmospheric concentrations of greenhouse gases.

REFERENCES

1. Humphreys, K.K. and Mahasenan, N (2001). Towards a Sustainable Cement Industry: Substudy 8: Climate Change. World Business Council for Sustainable Development, Conches-Geneva, Switzerland. 2. IPCC (2001). Climate Change 2001: The Scientific Basis. Intergovernmental Panel on Climate Change, Cambridge University Press, Cambridge, UK. 3. International Energy Agency (1999). The Reduction of Greenhouse Gas Emissions From The Cement Industry, Report PH3/7, Paris, France. 4. CEMBUREAU (1996). World Cement Directory, CEMBUREAU - The European Cement Association, Brussels, Belgium. 5. CEMBUREAU (1998). Cement Production, Trade, Consumption Data: World Cement Market in Figures 1913-1995, Worm Statistical Review No. 18, CEMBUREAU - The European Cement Association, Brussels, Belgium. 6. CEMBUREAU (1999). Cement Production, Trade, Consumption Data 1994-1997, Worm Statistical Review Nos. 19 and 20, CEMBUREAU - The European Cement Association, Brussels, Belgium. 7. Nakicenovic, N. and R. Swart, eds. (2000). Special Report on Emissions Scenarios, Intergovernmental Panel on Climate Change, Cambridge University Press, Cambridge, U.K. 8. Aitcin, Pierre-Claude (2000). Cement and Concrete Research. 30:1349.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1001

I M P R O V E M E N T IN ENERGY EFFICIENCY OF RE-ROLLING FURNACES FOR STAINLESS STEEL INDUSTRY AT JODHPUR, RAJASTHAN, INDIA U.P. Singh GM (PS), Petroleum Conservation Research Association ABSTRACT In India, there are a large number of stainless steel re-rolling mills in the small and medium sectors, located in three main clusters at Jodhpur, Ahmedabad & Delhi. The majority of these mills use furnace oil as fuel in their reheating as well as annealing furnaces to heat the stainless steel billets/sheets to rolling temperature of around 1250°C for the production of stainless steel sheets of required thickness and other items such as bar and rod stock. The Petroleum Conservation Research Association (PCRA) carried out energy audit studies in about 10 mills in the Jodhpur cluster during 1998-99 and identified large potentials for improvement in energy efficiency and reduction in GHG emissions through upgrading of technology in the re-heating and annealing furnaces of these mills. Over 80% of the stainless steel re-rolling mills have already upgraded the technology in their re-heating and annealing furnaces and the specific fuel consumption has come down from 80-100 liters/M.T, to around 35-40 liters/M/T. This has also resulted in about 60% reduction in GHG emissions. BACKGROUND

Steel re-rolling is the most popular method of producing finished steel all over the world. Almost all steel products made from steel are finished in the re-rolling/annealing process. With the increasing requirement of steel in the country and limitations of the main steel producers to meet this growing demand, the secondary steel sector is an alternative and viable source to meet the country's future steel requirements. In India, there are over 1500 mild steel re-rolling mills located in four main clusters, as well as other places. There are also a large number of stainless steel re-rolling mills located in three main clusters at Jodhpur, Ahmedabad and Delhi, as well as elsewhere within the country. The stainless steel sheets are used for manufacture of utensils and for industrial applications. In the Jodhpur cluster of stainless steel re-rolling mills, there are nearly 100 units. The Ahmedabad and Delhi clusters also have a high number of stainless steel re-rolling mills apart from other stainless steel re-rolling mills located at other places in the country. Most of the stainless steel re-rolling mills use furnace oil as fuel for heating raw steel sheets / billets to temperatures of about 1250°C, followed by annealing for the production of stainless steel sheets of required thickness and size, as well as bars and rod stock. R E - H E A T I N G AND A N N E A L I N G FURNACES

The re-heating/annealing furnaces are the heart of the stainless steel re-rolling mill. The primary energy sources used in the re-rolling mills are electricity, coal or fuel oil in the form of furnace oil, R.F.O., LSHS, and LDO. Thermal energy is required for heating the stainless steel sheets / billets before the rolling operations and the electrical energy is required to run the mill and other auxiliaries of the furnace, mill and lighting. The annealing furnaces also need electricity as well as furnace oil as a source of energy. The energy cost used to constitute about 4 0 - 50% of the total cost of the mills in this

1002

industry. This has now reduced to 25 -30% after incorporating technology upgrading in the fumaces. In view of the high cost of fuel, as well as scale losses, the rolling operation becomes viable only for an industry which operates at minimum cost. In order to achieve this, it is absolutely essential to study reheating and annealing furnaces in a scientific manner, so that they can be improved or modified to achieve optimum results. Even today, this idea has not been applied to many of the rolling mills and they continue to operate in a haphazard manner, resulting in a loss to the unit and national exchequer. In a re-heating and annealing furnace, to obtain the maximum efficiency, the following points have to be considered; Minimum and maximum size of raw material used in the furnaces. Maximum capacity required i.e. in tonnes per hour. This capacity has to be about 25% more than the mill capacity. Least consumption of furnace oil. Least possible scale losses. In order to obtain the above a real scientific analysis of the following is required to be done.

a) b)

c)

Inside volume of the fumace to accommodate the products of combustion. Correct profile of the furnace - there are three types of heat transfer - conduction, convection, and radiation. Of these, radiation is the most important and about 70-75% of the heat absorbed by the material is by radiation, which comes from proper profile of the furnace and correct placement of burners. Selection of combustion equipment such as, blowers, heating, pumping unit and burners. This plays a very vital role and the selection has to be on the basis of standard calculations. These aspects are more or less lacking in most of the Indian Stainless Steel rolling mills.

ENERGY AUDIT STUDIES CARRIED OUT BY PCRA As per its mandate, PCRA carried out energy audit studies in about ten numbers of stainless steel rerolling mills in Jodhpur cluster during 1998-99. Following areas were covered during the study: i) Performance of re-heating and annealing furnaces ii) Insulation of re-heating and annealing furnaces iii) Performance of Motors iv) Performance of Transmission Drive v) Study of Illumination Salient observations made during energy audit studies in these mills were as follows: 1. Efficiencies of furnaces were in the range of 30-32% which can be improved to 55-60%. 2. Large amount of heat is wasted in flue gases. Waste heat recovery should be done. Maximum waste heat can be recovered by preheating the metal. 3. Preheating of air by installation of a recuperator leads to better combustion. However primary air and secondary air will require different pressure and flow, which needs review of burner design. Also, there will be change in the process parameters at blower end, as well as at burner end. Accordingly process needs to be reviewed and blower parameters should be selected accordingly. 4. Preheating of combustion air/oil leads to higher flame temperature, which again leads to faster heat transfer. Due to this, increase in production can be expected. 5. Motors are driven through V belt drive hence for better efficiency energy efficient fiat belts can be used. 6. Illumination was reviewed. Better fitting and improved lighting will lead to better working environment along with saving. 7. The movement of the product was manual in both re-heating and annealing furnaces.

1003 8. The length of fumaces was varying from 12 to 14' at the inception stage, which was raised to 21' in course of time. 9. Stainless steel sheets in annealing furnaces were being fed and taken out from the front side only. GENERAL R E C O M M E N D A T I O N S MADE ON THE BASIS OF ENERGY AUDIT STUDIES IN STAINLESS STEEL R E R O L L I N G MILLS AT JODHPUR 1. Recycle Waste heat to the maximum extent possible 2. Use fuel efficient equipment 3. Use fuel efficient low excess air burners 4. Clean burner nozzles and oil filters regularly 5. Maintain pre-heat temperature of oil at the optimum level 6. Reduce excess air (keep CO2 above 13% or 02 below 3.5%) 7. Check thermal insulation 8. Have regular Energy Audit Studies carried out SALIENT FEATURES OF OLD DESIGN RE-HEATING & ANNEALING FURNACES A. The salient features / specifications of old design reheating furnaces are shown in Fig. No. 1, the details of which are as follows • i) The material is fed from the gate (1) ii) Material is coming out from gate (2) iii) Loading of material is manual on rollers iv) There are two burners installed on both ends of furnaces and are in operation continuously. v) Whenever the exhaust port is open, fuel consumption increases and hence the same is kept closed. Consequently, all the flue gases come out through gate no. 1 & 2 at a temp. of approximately 850°C. B.

The salient features / specifications of old design annealing furnaces, are as follows : i) The material is fed from the gate (1) ii) The material is taken out from the same gate (1) iii) Loading of the material is manual iv) There are three nos. of blowers for comfort of operators v) The burner is installed on the side of gate no. (1) and this is in operation continuously.

PCRA IMPROVED DESIGN R E H E A T I N G FURNACE A. PCRA developed an improved design reheating furnace having the following salient features/specifications which are shown in Fig. 2: 1. Provision for material preheating by increasing length of the furnace. 2. Optimizing number of burners and their locations. 3. Provision of a recuperater to pre heat combustion air by utilizing the waste heat content in the flue gases. 4. Improvement in furnace insulation and use of ceramic fibre for minimizing heat loss from outer surface of the furnace. 5. Entry of the material into the furnace from one end by a pusher arrangement and exit from the other end. B.

PCRA also developed an improved design annealing furnace having the following salient features/specifications which are shown in Fig. 3: 1. The length of fumace was increased to about 40' 2. Only one burner was provided on the front and of the furnace, from which material comes out 3. Provision of a recuperater to pre heat combustion air by utilizing the waste heat content in the flue gases.

1004 Improvement in furnace insulation and use of ceramic fibre for minimizing heat loss from outer surface of the furnace. The material enters the furnace from one end on rollers and comes out from the other end. C.

The salient features / specifications of PCRA improved design reheating & annealing furnaces are summarized as under : S.N.

2

3

PARAMETERS

OLD DESIGN R E H E A TING/A NNEALING FURNACE

PCRA 'S I M P R 0 VE D DESIGN R E H E A TING/AN NEALING FURNACE

SAVINGS

REMARKS

Length of Furnace

21 feet

33-40 feet

Upto 10%

Waste recovery

Metal ingots preheated Installed recuperator

Specific Fuel 80-100 Lit/M.T. 35-40 Lit/M.T. Consumption

Used ceramic fibre for insulation Saving of over 60%

heat No waste heat Temperature of Upto 10% recovery combustion air raised upto 260°C Improvement in Avg. skin temp. Max.Avg. skin Upto20% Furnace Insulation 120°C & above temperature up to 60°C

P C R A ' S R E C O M M E N D A T I O N F O R F U R T H E R I M P R O V E M E N T IN P E R F O R M A N C E OF R E H E A T I N G / A N N E A L I N G FURNACES Flue Gas Temp. is still high (400 °C and above). Further waste heat can be recovered by : i) Increasing preheated combustion air temp. ii) Installing regenerative burners. Presently heavy oil is used for combustion that requires higher air / fuel ratio & greater mass of flue gases emitted per kg of oil burnt. Introduction of gaseous fuel can reduce emissions. Use of PID controllers, provision of air curtains can reduce heat loss from charging & discharging doors. This will improve overall specific fuel consumption. Accurate control of material temperature. C O M P A R I S I O N OF P E R F O R M A N C E OF R E H E A T I N G FURNACES IN 3 NOS OF INDUSTRIES B E T W E E N OLD DESIGN FURNACES AND P C R A I M P R O V E D DESIGN FURNACES PCRA carried out additional energy audit studies after replacement of old design fumaces with PCRA improved design furnaces. The salient observations in three industries are shown in Table 1. I M P R O V E M E N T IN E N E R G Y E F F I C I E N C Y OF R E - R O L L I N G M I L L S F O R STAINLESS STEEL INDUSTRY AT JODHPUR, RAJASTHAN, INDIA About 80 steel re-rolling mills in the Jodhpur cluster have replaced the old design of re-heating and annealing furnaces with PCRA improved designed furnaces. This has resulted in a reduction in specific fuel consumption from a level of 80 to 100 lit/MT to 35-40 lit/MT. In view of growing demand for rerolled stainless steel products in the country, the stainless steel re-rolling mills at Jodhpur have increased their production capacities by almost 2.5 times, maintaining the earlier level of fuel consumption at around 31000 KL/Annum. With PCRA improved designed furnaces, at a furnace oil consumption level of 31000 KL/annum and specific fuel consumption of 90 liffMT (average), the total

1005

capacity of all the stainless steel re-rolling mills at Jodhpur was nearly 344, 450 MT/annum. For rerolling of the same quantity o f stainless steel with PCRA improved design furnaces having specific fuel consumption of 36 l i ~ T (average), the fuel oil consumption would only be 12400 KL. Thus, there is a saving of nearlyl 8,600 KL/annum of furnace oil for stainless re-rolling compared with the earlier level of 344,450 MT/annum. Therefore the improvement in energy efficiency

= 18,600 / 31,000 = 60%

R E D U C T I O N IN COz E M I S S I O N Specific gravity of fumace oil at 70°C = 0.90 Carbon contents in furnace oil = 86% by weight. Due to burning of furnace oil, CO2 is formed as per the following reaction: C+ 02 Therefore, saving in emission of CO2 due to reduction in furnace oil consumption by 18600 kl/annum

~ CO2

= 18,600 x 0.86 x 0.9 x 44 12 = 52790 M.T./annum

CONCLUSIONS PCRA has successfully developed an improved design o f reheating as well as annealing furnace for stainless steel re-rolling mills at Jodhpur, which has been adopted by over 80 steel re-rolling mills at Jodhpur. The energy cost in these mills has reduced significantly from a level of 40-50% to 25-30%, of the total cost o f the mills. In addition, fuel savings of about 60% and CO2 emissions reduction of more than 50,000 MT/annum have been achieved.

TABLE 1 COMPARATIVE PERFORMANCE OF REHEATING FURNACES AS PER OLD DESIGN AND PCRA IMPROVED DESIGN IN A FEW STAINLESS STEEL RE-ROLLING MILLS AT JODHPUR Name of Industry

Heat units

Input Heat i) Heatof fuel ii) SensibleHeat of Air Out put Heat i) Material Sensible Heat ii) Flue gas losses iii) Wall Losses/Rad.Losses iv) Other Losses

Chetan With old design urnace Kcal/hr %

Metal

883200 _

100 _

Surabhi Alloys

PCRA

Tri Murti Steels With PCRA design

With PCRA design

With

urnace Kcal/hr

%

design furnace Kcal/hr %

urnace Kcal/hr

%

321408 36519

89.8 10.2

480000 37628

92.7 7.3

288000 37628

88.4 11.6

165100

18.6

164190

45.9

190271

36.80

93210

28.80

581642 24179

65.8 2.7

121049 22274

33.8 6.2

225929 44683

43.60 8.60

111054 31082

34.20 8.60

112279

12.9

50414

14.1

56745

11.00

56745

19.40

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1007

IMPLEMENTATION OF A CORPORATE-WIDE PROCESS FOR ESTIMATING ENERGY CONSUMPTION AND GREENHOUSE GAS EMISSIONS FROM OIL AND GAS INDUSTRY OPERATIONS Susann Nordrum, Arthur Lee, Georgia Callahan ChevronTexaco Corporation 6001 Bollinger Canyon Rd., San Ramon, California, USA 94583

ABSTRACT

ChevronTexaco Corporation believes that global climate change is an important issue and is taking action to address it. We are responding to the concern about climate change with a four-fold plan of action. We are: • Reducing emissions of greenhouse gases and increasing energy efficiency • Investing in research, development and improved technology • Pursuing business opportunities in promising innovative energy technologies • Supporting flexible and economically sound policies and mechanisms that protect the environment. The ChevronTexaco Energy and Greenhouse Gas Inventory System (CEGIS) was designed and implemented to establish a reliable baseline and have a verifiable inventory of greenhouse gas emissions. This will enable us to pursue our goal of reducing emissions per unit output from our operations. CEGIS is an automated, electronic data management information system that is designed to gather monthly energy and greenhouse gas emissions data from ChevronTexaco's worldwide exploration and production, refining and marketing, petrochemicals, transportation and coal mining activities. The system was implemented throughout ChevronTexaco beginning in July, 2001. ChevronTexaco Corporation and its Chevron, Texaco and Caltex subsidiary companies enter data to calculate greenhouse gas emissions and energy utilization on a monthly basis. At the end of each quarter, energy and greenhouse gas emission estimates are reported to ChevronTexaco Corporation. This paper will review system scope and boundaries, provide an overview of how the system works and highlight lessons learned during company-wide implementation of the system.

INTRODUCTION

ChevronTexaco Corporation is a global company providing energy and chemical products and services vital to the growth of the world's economies. Our core values include a commitment to protecting the safety and health of people and the environment. This commitment is a critical component of the value we deliver to our stockholders, customers, government partners and employees.

1008 The ChevronTexaco Energy and Greenhouse Gas Inventory System (CEGIS) was designed to establish a reliable baseline and have a verifiable inventory of greenhouse gas emissions. This will enable us to pursue our goal of reducing emissions per unit output from our operations.

What is CEGIS? ChevronTexaco Corporation developed CEGIS using our decision-driven project management process. Representatives from the major business units actively participated in developing the system. In addition, we hired external consultants to gain perspective on greenhouse gas inventory issues and expertise in auditing. CEGIS is an Excel-based auditable energy and greenhouse gas inventory system, with calculations driven by a Visual Basic add-in. It is a comprehensive management system that provides for data collection, data entry, computation, compilation, reporting, record keeping and data management in an Oracle data base at the corporate level. CEGIS: • Requires monthly data input • Enables facilities to submit quarterly reports to the corporation • Requires documentation of data sources so that the data is verifiable • Provides for a consistent approach across all of ChevronTexaco • Yields emissions and energy utilization information that can be reviewed and analyzed by the facilities in real-time, enabling each facility to manage its own emissions. • Is highly automated, with the ability for transfer of input data from existing accounting systems into the spreadsheet, automatic quarterly reporting from facilities to the corporation and standard reports generated for each facility by the software. Key innovations are: • Combining greenhouse gas emissions and energy utilization estimates. Because the input data used to estimate energy utilization is a subset of data used to estimate greenhouse gas emissions, combining the estimates is more efficient for the user, eliminates rework, and ensures consistent energy utilization and greenhouse gas emission data for a given facility. • Developing an enterprise-wide, complete process for data generation, calculation, analysis, reporting and management. The ability to comprehensively manage data with automatic reporting, downloading, and Oracle database loading and query at the corporate parent level were integral to the design for ChevronTexaco's system. • The emissions and energy utilization estimation system is modular and Excel-based. The modules allow facilities to customize reports for their operations (e.g., downstream versus upstream). Use of Excel avoids the need for users to load and understand a new software environment. • The system uses the latest greenhouse gas estimating methodology developed by API [ 1].

CEGIS SCOPE AND BOUNDARIES

CEGIS scope and boundaries were discussed in a previous paper [2]. The scope and boundaries were initially designed based on the principles of completeness, credibility and control.

Completeness. In deciding whether to include or exclude an operation or source, we considered whether exclusion of the source would make our inventory materially incomplete. For initial inventory efforts, we attempted to be as inclusive as possible, with an emphasis on completeness over accuracy. For example, when data was not available, we estimated emissions from our non-operated

1009 joint ventures by using a ratio of greenhouse gas emissions per barrel of oil produced. The ratio was based on similar operations. Although this does not reflect the actual emissions from a non-operated venture, it does ensure that these emissions are assessed in our overall total.

Credibility. Some sources were included because the inventory would not be credible to external reviewers if the sources were omitted For example, contract drilling operations are included because these operations can have significant emissions and are closely associated with our business in some areas. Thus, an external reviewer/user of the data would not consider it to be a complete and credible report if we did not acknowledge the existence of emissions from drilling operations. Control. In some cases, we may have a very small working interest in an operation, but some degree of influence or control of emissions from the operation. For example ChevronTexaco is the contract operator of a production field in Venezuela. As the operator, we have the opportunity to implement some best practices to minimize greenhouse gas emissions. However, in this case, since we do not control capital investments, our ability to control funding for energy efficiency and/or greenhouse gas mitigation projects is limited. CEGIS includes three of the six greenhouse gases listed in the Kyoto Protocol. Carbon dioxide and methane were included because they are expected to be emitted from our operations in significant quantities. Nitrous oxide was also included in the inventory because it can be a minor byproduct of combustion. By including an assessment of nitrous oxide emissions, we can analyze the data to determine whether these emissions are significant to our overall inventory. The other three Kyoto gases were not included in our inventory because they are not expected to be emitted in significant quantities from our operations.

CEGIS I M P L E M E N T A T I O N

CEGIS was implemented in three phases. The first phase of implementation consisted of pilot tests at worldwide upstream and U.S. downstream locations. As a result of these tests, we made changes to CEGIS to make it more user-friendly, and to improve the flow of information. The second phase of implementation took place in July 2001, before the Chevron Texaco merger. Initial deployment of the software was done during a training class that was attended by representatives of all Chevron business units. After the training session, CEGIS users were given two months to configure the software for their business units and to enter data for the first nine months of the year. The first reports were to be submitted by mid-October, 2001, and the final year-end report was due in mid-January 2002. The report was to contain full year data for 2001 for each facility. In addition to the training session, help desk services were available to CEGIS users as they configured their systems, entered data and produced reports. The majority of the users were able to use CEGIS with little difficulty, and the majority of the reports were delivered on time. Users learned that it was best to have a good understanding of greenhouse gas emission sources, equity shares of operations, and location of facilities. With this information, users could draft a configuration plan before using the software. Although configuration can be changed at any time, it is easier and more efficient to complete the configuration with a minimum of revisions. Also, a comprehensive understanding of the operation helps ensure a complete inventory. The main problems occurred at facilities that did not have ChevronTexaco's common operating environment software. Because CEGIS was designed to be used with Windows NT and Excel 97, it did not always function properly with other combinations of operating systems and versions of Excel. In particular, facilities that had non-English versions of Excel typically encountered difficulties.

1010 During the first phase of implementation, users noted a number of improvements that could be made to CEGIS. For example, since estimation of criteria pollutant emissions often relies on the same data as estimation of greenhouse gas emissions, users requested that CEGIS be upgraded to include the capability of estimating criteria pollutant emissions. Another area of improvement was composition of flared gas. In the first version of CEGIS, the default composition of flared gas was consistent with the API Compendium, which suggests that as a default, the gas can be considered to be 100 percent methane. However, most users noted that associated gas tends to be comprised of about 80 percent methane, and the methane content can vary by as much as 20 percent. They therefore requested the ability to customize the composition of flared gas. Another driver for change was that ChevronTexaco's common operating environment was to be upgraded to Windows XP and Excel 2002, and the CEGIS software needed to be made compatible with this change. Starting in October, 2001, CEGIS was revised to incorporate learnings from the first phase of implementation. CEGIS 1.1 was issued in early 2002, and used in the third phase of implementation by all ChevronTexaco business units. The new version of CEGIS was designed so that existing users could transfer configuration and input information from their existing files to the new software, with little or no rework. This was a significant benefit, because some facilities had implemented highly detailed inventory systems, listing each emissions source individually. It would have taken a great deal of effort to re-enter all of that information. Also, retaining the configuration makes it easier to compare data from year to year. The third phase of implementation took place in March 2002, after the ChevronTexaco merger. The session incorporated lessons learned from the first phase of implementation. We continue to provide help desk support, and note a high level of activity every three months when the quarterly reports are due. With roughly 70 users, we receive many suggestions for improvements, and plan to incorporate as many as possible into the next version of CEGIS, which we expect to issue at the end of this year.

WHAT W E ' V E LEARNED Successes

• • • • • • •

Implementation of a companywide data management system has enabled us to develop a consistent, high quality energy and greenhouse gas inventory. Because CEGIS includes all the calculational methodologies, we can make meaningful comparisons of data from facility to facility (comparing "apples to apples"). The existence of a common operating environment was a major factor in enabling us to deploy this type of inventory system. Involvement of current and future CEGIS users in development of the system both improves the software and promotes user acceptance. Users who had prior experience with energy management systems generally found it easier to understand and use the CEGIS system. The additional effort and planning needed to configure the CEGIS system yields significant longer-term efficiency benefits in data entry and management. Because the CEGIS system is designed to enable upgrades to be implemented without forcing users to reconfigure their systems, CEGIS will continue to be relevant as greenhouse gas emissions estimating methodologies and practices continue to evolve.

1011 •

•

• • • • • •

CEGIS includes a 'Compositions' sheet that enables users to easily convert between mass and volume data, and to get information on the heating value, density and emission factors for a gas. This sheet has proven useful both in CEGIS configuration and for other work. CEGIS allows the user to choose units of measure for data entry. This minimizes the need for users to do unit conversions and therefore reduces the chance for error. CEGIS output data can be specified by the user to be shown in metric tonnes or standard tons. Data is sent to the corporate database with common units of measure (metric tonnes of emissions). Users can add, modify or remove sources as needed in order to keep the CEGIS configuration up to date as operations change. The CEGIS software is password protected in a Visual Basic add-in, so that users cannot inadvertently change the methodologies. The CEGIS reporting process is designed so that old versions of CEGIS can be detected, enabling us to ensure that users are running the latest version. Because audit trail information is required before data submittal, the CEGIS software facilitates development of an auditable inventory. The inventory system was designed to be converted to a Web-based system in the future. CEGIS uses Excel as its basis, so emissions data is readily available to the user for analysis and reporting. Users can create charts and tables from the data using standard Excel capabilities.

Areas for Improvement •

•

•

• •

•

•

The first area for improvement will focus on quality assurance and quality control (QA/QC) procedures both at the data reporter level and at the corporate level. A plan is being implemented currently to facilitate self-check at the data reporter level. Further, the QA/QC of numbers, based on materiality of the emissions and the production is performed rigorously by corporate staff beginning with data submitted in the first and second calendar quarters of 2002. The CEGIS users guide was written more as documentation than as an aid to the user. It could be improved by using case studies to illustrate how to configure the software and how to resolve common problems. Further, a ChevronTexaco Protocol Document will be developed to establish emissions accounting principles and specific guidance on boundary issues and QA/QC procedures. Flaring and combustion are separate modules, which enables us to review flaring emissions separately from other types of combustion. However, to make the system more user-friendly, these two modules should be as similar as possible. Some users found it difficult to use the 'modify' or 'remove' functions of CEGIS. It is much easier to perform initial configuration than to make revisions. Some regulatory agencies prefer to see combustion data divided between stationary and mobile sources. Although this distinction can be made if CEGIS is properly configured, it would be easier if CEGIS was specifically designed to the separate these two types of emission sources (i.e., separate modules for stationary and mobile sources). Published emission factors for nitrous oxide are generally of low quality. Further analysis of the data is needed to determine whether better factors need to be developed, or whether nitrous oxide emissions are insignificant. The Visual Basic for Applications (VBA)--Excel interface is not always sufficiently robust to handle the calculations and data manipulation automatically. In some cases, users have to exit and re-enter the system in order for changes to be accepted. This is an inherent problem with the platform have chosen, and can be remedied by converting to Visual Basic.

1012 CONCLUSIONS Implementation of a companywide software system for consistent estimation of energy, greenhouse gas and criteria pollutant emissions yields numerous benefits. User involvement in development and ongoing improvement of the software is key to successful implementation. Ongoing, centralized support is necessary to keep the system relevant as greenhouse gas emission estimating methodologies and software environments continue to evolve.

REFERENCES

American Petroleum Institute (2001). Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Inventory; Pilot Test Version; API, Washington, D.C. 2. Nordrum, S., Lee, A. (2002). Development of a Corporate-wide Process for Estimating Energy Consumption and Greenhouse Gas Emissions from Oil and Gas lndustry Operations. ChevronTexaco Corporation, San Ramon California. 1.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1013

T H E R M O N E U T R A L CO-PRODUCTION OF METALS AND SYNGAS WITHOUT GREENHOUSE GAS EMISSIONS

M. Halmann 1 and A. Steinfeld 2 Weizmann Institute of Science, Department of Environmental Sciences and Energy Research, Rehovot 76100, Israel. 2 ETH - Swiss Federal Institute of Technology, Department of Mechanical and Process Engineering, CH-8092 Zurich, Switzerland.

ABSTRACT

The industrial production of iron and other metals, as well as the production of syngas, are energy-intensive processes that account for more than 10% of the annual anthropogenic release of CO2 to the atmosphere, derived mainly from the combustion of fossil fuels for heat and electricity generation. There exists an urgent need to provide economically viable alternatives to the above processes that are less wasteful in fossil fuel resources while avoiding the release of greenhouse gases and other pollutants. In a novel metallurgical process, the endothermic reduction of metal oxides is combined with the exothermic partial oxidation of hydrocarbons to co-produce, by thermo-neutral reactions, both metals and syngas. The conditions for thermoneutrality were established by thermochemical calculations for the reduction of ZnO, Fe203, and MgO to the metals, using CH4 as reductant, and 02 as the oxidant. Confirmation of the calculated processes was obtained by thermogravimetric experiments, measuring simultaneously both the weight loss during the reduction of ZnO or FezO3 under a flow of Ar, CH4, and 02 at 1 bar and 1273 or 1400K, as well as the formation of H2, CO, and CO2 by gas chromatography. A preliminary evaluation indicates that such a process, followed by the production of either hydrogen or methanol, should be economically competitive, while significantly decreasing the release of COz. INTRODUCTION

The iron and steel industries are highly energy-intensive processes, releasing annually about 1.2x109 tons of CO2, and contributing about 5% to the anthropogenic greenhouse gas emissions [ 1,2]. In the carbothermic production of iron, the main endothermic reactions are, Fe203 + 1.5C = 2Fe + 1.5CO2

AH°298K = 235 kJ mol l

(1)

Fe304 + 2C

AH°298K = 333 kJ mo1-1

(2)

= 3Fe + 2CO2

1014 In an effort to achieve a cleaner process, a modification of the direct reduction of iron oxides by syngas or natural gas has been proposed, in which the endothermic reduction of iron oxides by methane [3 ], Fe203 + 3CH4 = 2Fe +3CO + 6H2

AH°298K = 719 kJ mol

(3)

Fe304 + 4CH4 = 3Fe +4CO + 8H2

/~x-'I0298K- 978 kJ mol "]

(4)

is combined with the exothermal partial oxidation of methane [4], CH4+1/202 = CO+2H2

AH°298K =-38 kJ mol -I

(5)

resulting in an overall thermo-neutral process, with syngas as a valuable by-product [5]. By achieving both environmental improvement and economic advantage, such a new process may be more readily adopted by industry [6]. In the present work, the thermodynamic constraints for the above combined process are explored, using methane as the reductant of iron oxide. Thermochemical equilibrium calculations were made using computational codes [7-10]. The results of these calculations were applied to the economic evaluations described in Tables 1 and 2, as well as to the environmental assessments. Experimental tests were carried out using thermogravimetry to measure the reduction of Fe203 and Fe304 to Fe under a constant stream of Ar, CH4 and 02, while simultaneously measuring by gas chromatography the appearance of H2, CO, and CO2. The technique was as previously described [11]. A preliminary economic evaluation is for a proposed large-scale industrial plant to produce annually about 0.5 million metric tons of iron, using natural gas as the reductant, with the syngas converted either to hydrogen or methanol. E X P E R I M E N T A L RESULTS Figure 1 describes the time course of mass loss during the reduction of Fe203, the consumption of CH4 and O2, and the production of H2, CO, and CO2. Under the given conditions, the weight loss from Fe203 via Fe304 and FeO to Fe was complete within 40 min. The concentrations of H2, CO, and CO2 remained fairly constant, even after the Fe203 had been reduced to Fe, presumably because the Fe formed catalyzed the CH4 partial oxidation/CO2 reforming. 100 mg Fe2Oa / 5.1% CH413.6% 02 / 1400 K

120 ~ 100 ~ e

5 4

UMass

** 3 5

+ 02 --i--H2

20

1

"¢t:'CO

0

0

60

i i 40 0 i

"''C.L_

20

40

/

---I-- CH4

2~ -=-c02 60

80

Time I min

L Figure 1. Thermogravimetric experiment with Fe203 under Ar - CH4 - 02 (91 : 5.1 : 3.6 by volume) at 1400 K and atmospheric pressure.

1015 ECONOMIC EVALUATION The proposed plan is for a plant to produce annually 0.5 million mt (metric tons) of iron, using natural gas (NG) as the reductant, and oxygen for the partial oxidation. The co-produced syngas is converted either to hydrogen (Table 1), or to methanol (Table 2), thus substantially improving the process economics. The plant is assumed to be down 20% of the time for maintenance. The estimated capital cost is US$200/mt of iron, which is similar to that of planned plants in Australia and the U.S. [12]. The main uncertainties are the size of the capital cost, the highly variable costs of natural gas and oxygen, and the market prices of the products. The proposed plant would add about 0.1% to the world production of iron, and about 5% to the world capacity of methanol, which in 2001 amounted to 33.8 million mt [13]. No credit has been included in these calculations for the sale of the purified CO2 resulting from the PSA (pressure swing absorption) process. For the case described in Table 1, the production of CO2 would reach 0.97x106 mt/zvr. At the reported average price of US$12/mt [14], its annual sale would amount to US$11.6x 10°, thus further improving the economics of the process. GREENHOUSE GAS RELEASES The annual world production of iron from its ores amounts to about 0 . 5 x 1 0 9 tons, releasing about 1.2xl 09 tons of CO2 [2]. Thus the molar ratio of CO2 formed to Fe produced is CO2/Fe = 1.2x55.85/(0.5x44) = 3.05. For comparison, in the above proposed co-production of Fe and H2 (as in Table 1), the predicted molar ratio of CO2 formed to Fe + H2 produced (after complete water-gas-shift of CO) will be CO2/(Fe+H2) = (3.7+1.2)/(2.0+5.7+3.7) = 0.43. For the case of the co-production of Fe and methanol (as in Table 2), in which the syngas ratio will be partly shifted to reach H2/CO = 2, the molar ratio CO2/(Fe+H2) will be only 0.19. Current markets for methanol are formaldehyde (35.5%, mainly for polymers), various chemicals and solvents (30.8%), methyl-tert-butylether (the fuel additive MTBE, 27.4%), and acetic acid (6.4%) All of these, except MTBE, are long-term sinks for carbon [6]. REFERENCES

10.

Ullmann's Encyclopedia of Industrial Chemistry, 5th Ed. (1989) vol. A14, p. 516. Steinfeld, A., and Thompson G. Energy (1994) 19, 1077-1081. Barrett, D. Ind. Eng. Chem. Process Develop. (1986) 11, 415-420. Ashcroft, AT, Cheetham, AK, Green, MLH, and Vernon ODF, Nature (1991) 352, 225-226. Halmann, M., Frei, A., and Steinfeld, A., 6th Internat. Conf. On Carbon Dioxide Utilization, Breckenridge, CO., USA (Sept. 2001) Abstract PO-16. Halmann, MM., and Steinberg M., Greenhouse Gas Carbon Dioxide Mitigation: Science and Technology, Lewis Publ. (1999). Roine, A., Outokumpu HSC Chemistryfor Windows, Version 4.1: Outokumpu Research Oy, Pori, Finland (1997). Thermochemical Software & Database Package F*A *C'T, Centre for Research in Computational Thermochemistry, Ecole Polytechnique de Montreal, Canada, www.crct.polymtl.ca. Gordon, S. and McBride, J. B., NASA SP-273, NASA Lewis Research, Cleveland, OH (1976). A PC version prepared by T. Kappauf, M. Pipho, and E. Whitby for E. A. Fletcher at the University of Minnesota was used in the present study. National Institute of Standards and Technology, Standard Reference Data Program,

1016

11. 12. 13. 14.

Chemistry Webbook, http://webbook.nist.gov. Steinfeld, A. Frei, A., Kuhn, P. and Wuillemin, D., Int. J. Hydrogen Energy (1995) 20, 793-804. See www.ausmelt.com.au/comops_sase.html. Also: www.indiainfoline.corn/stee/pr08.html. See www.methanex.com/methanol. See www.ieagreen.org.uk/util4.htm.

TABLE 1 ECONOMIC EVALUATION FOR Fe AND H2 PRODUCTION FROM Fe203 AND NG. A designated reaction mixture of Fe203 - CH4 - 02 (molar ratio 1 : 4.87 : 3.5) at 1400 K and 1 bar in a thermo-neutral reaction forms an equilibrium mixture of Fe, H2, CO, H20, and CO2 (molar ratio 2.0 : 5.7 : 3.7 : 4.0 : 1.2). By water-gas shift, the CO is converted to hydrogen.

Assumptions Annual Fe203 feed (kmol/yr) Annual Fe203 feed (mt/yr) 1 Annual NG feed (kmol/yr) Annual NG feed (GJ/yr)2 Annual NG feed (mmbtu/yr) 3 Annual 02 feed (mt/yr) Fe production (mt/yr) H2 production (kg/yr) = H2 production (GJ/yr)" Capital Cost (million US$)

Equipment and facility 6 Interest during construction (10% of facility investment) Startup expenses & working capital TOTAL

4.5x106 0.72xl 06 21.9x106 19.5x106 18.5x106 0.50x 106 0.50x106 65.7x106 9.33x106 100 10 10 120

Annual Cost (million US$) Capital cost (15% of Total) Operation & Maintenance (2% of Total) Fe203 cost (US$4.60/mt) 7 NG cost (US$3.50/mmbtu) 8 02 cost (US$40/mt) 9 TOTAL

18.0 2.4 3.3 64.8 20.0 108.5

Annual Sales (m~llion US$) Iron (US$130/mt) H2 (US$0.71/kg) 1° TOTAL

65.0 46.6 111.6

1 mt = metric ton = tonne. 2 Taking 890.8 kJ/mol for the heat of combustion of CH4. 3 1 mmbtu = 1 million btu = 1.055 GJ; 1 GJ = 0.278 MWh. 4 Assuming 75% overall yield of conversion of CH4 to H2. 5 Taking HHV (Higher Heating Value) of H2 = 142 MJ/kg = 0.142 GJ/kg. 6 Including the reactor, desulfurization, heat recovery, shift reactor, PSA, and other related equipment and facility. 7 See www.ausmelt.com.au/comops_sase.html. 8 May 2002. Source: International Herald Tribune. 9 See Basye, L. and Swaminathan, S. "Hydrogen Production C o s t s - A Survey", 1997; Report by SENTECH, Inc. for DOE/GO/101-778. 10 See www.eren.doe.gov/hydrogen.

1017 TABLE 2 ECONOMIC EVALUATION FOR IRON AND METHANOL PRODUCTION FROM Fe203 AND NG A designated reaction mixture of Fe203 - CH4 - 02 (molar ratio 1 : 4.87 : 3.5) at 1400 K and 1 bar in a thermo-neutral reaction forms an equilibrium mixture of Fe, H2, CO, H20, and CO2 (molar ratio 2.0 : 5.7 : 3.7 : 4.0 : 1.2). Following partial water-gas shift, the syngas (H2 + CO) is converted to methanol.

Assumptions Annual Annual Annual Annual Annual Annual Annual Annual Annual

Fe203 feed (kmol/yr) Fe203 feed (mt/yr) 1 NG feed (kmol/yr) NG feed (GJ/yr)2 NG feed (mmbtu/yr) 3 02 feed (mt/yr) Fe production (mt/yr) methanol production (kmol/yr) 4 methanol production (mt/yr)

415xi06 0.72x10 6 21.9x106 19.5x106 18.5x106 0.50x106 0.50x106 13.1 x106 0.42x106

Capital Cost (million US$) Equipment and facility ~ Interest during construction (10% of facility investment) Startup expenses & working capital TOTAL

100 10 10 120

Annual Cost (million US$) Capital cost (15% of Total) Operation & Maintenance (2% of Total) Fe203 cost (US$4.60/mt) 6 NG cost (US$3.50/mmbtu) 7 02 cost (US$40/mt) 8 TOTAL

18.0 2.4 3.3 64.8 20.0 108.5

Annual Sales (m~llion US$) Iron (US$130/mt)' Methanol (US$206/mt) 9 TOTAL

65.0 86.5 151.5

1 mt = metric ton = tonne 2 Taking 890.8 kJ/mol for the heat of combustion of CH4 3 1 mmbtu = 1 million btu - 1.055 GJ; 1 GJ = 0.278 M W h 4 Assuming 60% overall yield of conversion of CH4 to CH3OH 5 Including the reactor, desulfurization, heat recovery, shift reactor, PSA, methanol synthesis reactor, and other related equipment and facility 6 See <www.ausmelt.com.au/comops_sase.html> 7 May 2002. Source: International Herald Tribune. 8 See Basye, L. and Swaminathan, S. "Hydrogen Production C o s t s - A Survey", 1997; Report by SENTECH, Inc. for DOE/GO/101-778. 9 U.S. Gulf spot price for methanol in barges, May 2002. See: www.methanex.corn/methanol.

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1019

AN ANALYTICAL METHOD OF CONSTRUCTING BEST-MIXED POWER GENERATION SYSTEMS REFLECTING PUBLIC PREFERENCE R. Akasakal, N. Shikasho 2, K. Morita 1 and K. Fukuda 1 1 Institute of Environmental Systems, Kyushu University, 6-10-1 Hakozaki, Higashiku, Fukuoka, Japan 2 Graduate School of Engineering, Kyushu University

ABSTRACT An investigation into consumers' preference for power generation systems was performed. It was found that most consumers preferred values that incorporated 'social acceptability' and 'environmental effect' in constructing the energy system. An analytical method to evaluate the best combination of power generation systems to meet consumers' preference was developed. It was applied in the evaluation of each of the selected combinations of systems that met each consumers' requirements. The resulting best combinations of systems were comprised mainly natural gas-fired power and hydraulic power generation system. The power systems with disadvantages in terms of the 'social acceptability' and/or 'environmental effect' were barely introduced. The duality theorem allowed us to evaluate the marginal cost of consumers' preferences. The 'social acceptability' yielded the highest marginal cost, and the 'environmental effect' was the next. INTRODUCTION

There are many controversial issues in terms of the energy problem. Energy suppliers are now forced to take into account environmental effects and safety, at the cost of less commercial profit. Although they intend to build more nuclear plants, it is sometimes difficult to meet the concerns of the opposition, people who fear the risk of a severe accident or have concerns about the waste disposal from such power plants. On the other hand, energy consumers expect alternative natural energy resources, such as the solar energy, as the main energy resources in the near future. However, at this moment, it is assumed that natural energy resources are rather expensive and their technologies are yet immature. Unfortunately, three participants of the energy society, suppliers, consumers, and the government, barely evaluate the unmeasurable values of energy resources, or the energy externalities, because of their complexity and variety. Under this situation, arguments among the participants on future energy systems are often confused. Recently, especially after 1980, in the field of nuclear engineering, many subjects about the best combination of power generation systems, or simply the 'best-mix', have been discussed, recognizing the externality of nuclear power. In Japan, Mankin et al. [1] estimated an increase in investment for small- or middle-scale nuclear reactors in the future, and predicted that it would be compatible with that for large-scale nuclear reactors. Ohkubo et al. [2] produced a new model to simulate the future energy best-mix, and using the model, were able to advise in Japanese policy on nuclear power. The authors also evaluated the role of nuclear energy in terms of energy security of the country [3]. In other countries, Afanasiev [4] revealed an economical advantage for Russian nuclear power over other types of power generation, using the concept of marginal cost. After the agreement of the Kyoto Protocol, marginal cost estimations for the reduction of greenhouse gas

1020 emissions have focused in the field of environmental engineering. Kainuma [5] reviewed several economic models to achieve the Kyoto Protocol Standard, and pointed out that Japan had higher marginal cost to reduce the CO2 emissions than other countries. Yoshida et al. [6] proposed a new energy model, minimizing power generation costs, and predicted that the marginal cost to reduce CO2 emissions would become dramatically higher when the growth of nuclear power generation approached saturation. Jackson [7] compared some technologies for the reduction of greenhouse gas emissions based on their marginal costs. However, few discussions have focused on constructing energy system reflecting consumers' preference. Thus, we developed a method to determine public preference based on responses to a questionnaire [8], and to establish the best-mix which reflected that preference [9,10]. In this study, applying this method, a survey on energy consumers' preference was conducted, and the best-mix that reflected this preference was evaluated. In the analysis, the linear programming algorithm was applied, with the duality theorem; marginal costs for various external values were also evaluated.

ANALYTICAL METHOD

Investigation of Energy Consumers' Preference The questionnaire shown in Figure 1 examined consumers' preference for the following five values: economical efficiency, convenience, energy security, environmental effect, and social acceptability, which were classified by factor analysis as the essential values regarding energy-related problems. Except for economical efficiency, all of the remaining four values could be regarded as external values. The questionnaire was composed of ten questions based on the AHP (Analytical Hierarchy Method), a multivalue decision support method designed to assess the relative importance among alternatives. Pairwise comparisons were carried out to produce an overall ranking table of preference for values, e.g., "Which do you think is more important for the power generation, economical efficiency or environmental effect?" All of the preferences for each value were normalized to be the range between 0 and 1. Please choose one suitable for your idea. (a) more important than (b) a little more important than (c) as important as (d) a little less important than (e) less important than. Q1. Economical efficiency Q2. Economical efficiency Q3. Economical efficiency Q4. Economical efficiency Q5. Convenience is Q6. Convenience is Q7. Convenience is Q8. Energy security is Q9. Energy security is QIO. Environmental effect

is is is is

is

convenience. energy security. environmental effect. social acceptability. energy security. environmental effect. social acceptability. environmental effect. social acceptability social acceptability.

Figure 1: Questionnaire to investigate a consumers' preference for values. Performance of Power Generation System In constructing the best-mixed power generation, the following eight systems are employed: oil fired (OIL), coal fired (COA), natural gas fired (LNG), hydraulic (HYD), photo-voltaic (SOL), light water reactor (LWR), high temperature gas cooling reactor (HTGR), and fast breeder reactor (FBR) power generation systems. An assessment of these systems is performed in terms of five values described above, and the performance score for each system for each value are evaluated.

1021

As shown in TABLE 1, several specifications related to each value are selected; e.g., capital cost, maintenance cost, and fuel cost are taken to assess the value 'economical efficiency'. Similarly, emissions of CO2, SOx, NOx, and radioactive waste are chosen for assessment o f the value 'environmental effect'. The quantitative specifications such as costs or amount of emissions of exhaust are available from literatures. These are carefully determined referring the latest publications. However, some qualitative specifications, such as 'technological maturity', contained in TABLE 1 are difficult to evaluate. To do this, the AHP is applied. All specifications thus evaluated are weight averaged and summarized to give the respective performance scores. The weights are also determined by AHP. The performance scores of each system are tabulated in TABLE 2. These are reduced to the standard deviation score, where zero indicates an average. If a score is positive, it is superior to the average performance, and if negative, it has less performance. TABLE 1 VALUES AND SPECIFICATIONS TO EVALUATE THE PERFORMANCE OF POWER GENERATION SYSTEMS Value Economical efficiency

Convenience

Energy security

Environmental effect

Social acceptability

Specification Capital cost Maintenance cost Fuel cost Technological maturity Energy density Easiness to handle the waste Amount of resource Distribution of resource Easiness of fuel storing or self supplying CO2 emission SOx emission NOx emission Radioactive waste Human damage System risk Local agreement Possibility of large-scale accident

TABLE 2 PERFORMANCE SCORES OF EIGHT SYSTEMS

Economical efficiency Convenience Energy security Environmental effect Social acceptability

OIL 0.388 0.241 -0.861 -0.542 -0.054

COA 0.388 -0.339 -0.729 - 1.247 -1.065

LNG 0.460 0.285 -0.843 -0.114 0.296

HYD SOL LWR HTGR FBR 0 . 1 9 1 -2.464 0 . 4 6 5 0 . 2 8 6 0.268 0 . 5 7 6 -0.501 -0.279 0 . 0 3 7 -0.020 1 . 2 5 4 1 . 2 5 4 -0.352 -0.352 0.629 0 . 6 9 3 0 . 4 7 8 0 . 2 4 2 0 . 2 4 2 0.242 0 . 0 3 5 1 . 2 7 4 -0.140 -0.140 -0.207

Linear Programming Figure 2 illustrates the process used to find the best-mix, applying the linear programming method (LP) [9,10]. The preferences of five values, which vary depending on examinees, are the input to LP. The LP searches the solution that minimizes the total cost to construct the best-mix. The problem is formulated as follows.

1022 8

Minimize z = ~ c,x,

(1)

i=l 8

subject to ~S~x, > bj (j = 1..5)

(2)

i=l 8

(3)

~-'x,-1 t=l

x, _>0 (i = 1..8)

(4)

where x, and c, are the composition and the power generation cost of a system i, respectively, bj is the preference for the value j , S~ the performance score of system i for value j . Only x, is unknown and q, bj, and Sv are fixed during minimization. The right hand side of Eqn. 1 is the total cost to be minimized. Eqn. 2 imposes a requirement that a sum of the product to the performance score Sv and the composition x, with respect to all power generation system should exceed the preference bj of the value j . To solve the LP, the simplex algorithm is adopted.

Performancescoresof systems I Input I Preference°f values

I Linearprogramming

I mmkll

Output Compositionof systems I

Figure 2: Process to find the best-mixed power generation

Dual Problem

The duality theorem belongs at the center of the underlying concept of the LP, which gives the dual problem formulated as follows: Maximize w = ~ bjyj + Y6

(5)

)=1 5

subject to ~ Suyj + Y6 -< Ci (i = 1..8)

(6)

j=l

yj _>0 (j = 1..5)

(7)

where yj, the variable in the problem, gives the marginal costs of the constraint conditions of the primal problem.

RESULTS AND DISCUSSIONS

Preference A survey was conducted from October to December 1999. Figure 3 shows the result of preference for values obtained from the survey. The abscissa and the ordinate are the percentage of examinees and their preference, respectively. A preference of 0.2 indicates an average. If an examinee regards that a certain value is more important than the others, its preference is grater than 0.2.

1023 About 90% of the examinees thought that the value 'social acceptability' was of above average importance, and the 'environmental effect' and 'energy security' were the next. Few examinees put their preference on the ' economical effect' and ' convenience'.

0.6.

•

,

,. 0 514"'. • I~ ~" 0.4~,'~,

i

,

i

",,

~t :,,_

,

....

"'- ...... ":'-

o.:3

i

,

i

, j

.... Economical efficiency ---- Convenience --Energy security .... Environmental effect - -- Social acceptability

"

.....

a. 0.2

. . . . . _".~-.

01f ,

I

0

,

I

20

,

I

40 Percentage

,

I

60

,

80

100

(%)

of examinees

Figure 3: Preference of each value

Best-mixed Power Generation System Figure 4 shows the best-mix to accord with the examinees' preference, evaluated by the procedure described above. The abscissa and the ordinate are the percentage of examinees and the composition of each power generation system in the best-mix, respectively. LNG and HYD comprised large part in most of the best-mix evaluated for all examinees' preference. This was reasonable because these power generation systems have relatively high performance scores for the social acceptability as tabulated in TABLE 2. Some best-mixes contained a small composition of SOL and LWR. Although SOL had the best score for the social acceptability in all systems, its economical score was considerably less than the others. Therefore, it was contained only in the best-mix of examinees who regarded the social acceptability as extremely important. The reason for including LWR was that it had average performance for all values. The best-mix that contained OIL, COA, HTGR, and FBR hardly appeared. OIL and COA had few advantages except for economical efficiency and convenience, which were not considered as highly important. HTGR and FBR had average performances, almost the same as LWR, but the lower economical performances were a disadvantage.

•

0.8

~

0.6

LNG

o

0.4 Q. ~ 0.2 U

_

so,

2~)

'

,,,'0

Percentage

'

_

s~)

of examinees

-'7""-,-'-, 80

100

(%)

Figure 4: Composition of each system in the best-mix

1024

Marginal Costs Figure 5(a) shows the marginal costs of values calculated individually for all examinees' preferences, while Figure 5(b) shows the marginal costs averaged. The highest marginal cost of the social acceptability meant that most examinees were willing to pay the highest expense for the social acceptability. This result was acceptable, in that marginal costs of the environmental effect and the energy security followed. As mentioned above, these values were regarded as important, next to the social acceptability. The fact that the marginal costs of the economical efficiency and the convenience were consistently zero was also remarkable. This was interpreted that all examinees were prepared to incur no expense for these values, since their requirement for these value had already been satisfied. 25

!

!

!

S o c i a l acc e p t a b ility

3:

~ 25 20

20 >'15

'~u Environmental •,-.

lO

effect

10

u .-~

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5

1

security

\

,

o

'

~)

",'0

'

6'0

'

P e r c e n t a g e of e x a m i n e e ( % )

(a)

8'o

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o

~

oo ~o

~ m o

~

~

O

~

~

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Figure 5: Marginal cost for values (a) individual (b) averaged CONCLUSIONS The prime problem in finding the best-mixed power generation system for energy consumers was discussed. The linear programming approach solved the problem, and the best-mix was evaluated individually, according to the preference of each consumer. The dual problem that the duality theorem derived from the prime problem was discussed. A solution of the dual problem gave the marginal cost values for consumers' preferences. The survey of energy consumers' preferences revealed that the examinees tended to attach the most importance to social acceptability, and in their best-mixes, the LNG and HYD were selected in greater percentages than the others. It was understood from the resultant marginal costs that most examinees approved the meeting of the highest expense for social acceptability. The marginal cost is regarded as the price representing the 'willingness to pay' for values in constructing the best-mix. REFERENCES

.

4. 5. 6. 7. 8.

9. 10.

Mankin, S., Sato, O., Yasukawa, S. and Hayashi, T. (1998) Nucl. Eng. Des., 109, 355. Ohkubo, H., Suzuki, A. and Kiyose, R. Journal of Faculty of Engineering (1982) The University of Tokyo, Series B, 36, 4, 787. Fujimoto, N. and Fukuda, K. (2000) Trans. Japan Soc. Energy Resources, 21, 5,438. Afanasiev, A. A., Boldshov, L. A. and Karkhov, A. N (1997) Nucl. Eng. Des., 173, 219. Kainuma, M., http://www-cger.nies.go.jp/cger-j/c-news/vol 10-4/vol 10-4-2.html Yoshida, Y., Ishitani, H. and Matsuhara, R. (1995) J. Jpn. Soc. Simul. Technol., 14, 1, 52. Jackson, T. (1991) Energy Policy, 19, 1, 35. Harada, Y., et. al., (1997) Eng. Sci. Rep. Kyushu Univ., 18, 4, 289. Fukuda, K., Fujimoto, N., et. al., (1998) ibid, 20, 1, 19. Fujimoto, N., et. al., (2001), Technol. Rep. Kyushu Univ., 74, 3, 221.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1025

APPLICATION OF THE API C O M P E N D I U M OF GREENHOUSE GAS EMISSIONS ESTIMATION METHODOLOGIES FOR THE OIL AND GAS INDUSTRY TO EXAMINE POTENTIAL EMISSION REDUCTIONS K. Ritter, ~ S. Nordrum, 2 and T. Shires 3 ~American Petroleum Institute (API), 1220 L Street, NW, Washington, D.C. 20005 2ChevronTexaco, 2613 Camino Ramon, San Ramon, CA 94583 3URS Corporation, 9400 Amberglen Blvd., Austin, TX 78729

ABSTRACT In response to continued interest by its member companies about consistency in greenhouse gas (GHG) emissions estimation, the American Petroleum Institute (API) developed a Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas lndustry [ 1]. Initially distributed in June 2001, the Compendium is a result of more than a year long effort by API to screen, evaluate and document a range of calculation techniques and emission factors that could be useful for developing GHG emissions inventories. In a continued effort to enhance the real-world application of the Compendium, API is examining the applicability of the Compendium methodologies to assess emission reductions from specific projects. This paper presents findings from this follow-on activity. Although the reduction activities presented may not be applicable to all locations, and the estimated emission reductions may not be achievable for all situations, the purpose of this study is to illustrate use of the Compendium and identify potential methodological issues. This paper examines technical considerations associated with estimating pre- and post-project emissions and discusses the criteria being set forth in the international community regarding requirements for reliable emission reduction projects.

INTRODUCTION

Background Greenhouse gas inventories and emission estimation methodologies have been evolving over the past decade. Inevitably, as different organizations and governing bodies develop inventories and emission estimation methodologies, the level of detail and type of emission sources will vary. This presents a logistical challenge to the oil and gas industry, whose operations span the globe and thus encounter a variety of rules, policies and guidelines. Recognizing the need for consistency in the methods used to quantify greenhouse gas emissions, API's member companies compiled recognized "best practices" for emission estimation methodologies applicable to oil and gas industry operations. The resulting Compendium can be used to guide the estimation of GHG emissions for individual projects, entire facilities, or company-wide inventories.

1026 The Compendium currently targets carbon dioxide (CO2) and methane (CH4) emissions, the two most significant GHG emissions for the oil and gas industry. Emissions from oil and gas industry operations are grouped into five categories: combustion devices, point sources, non-point sources, non-routine activities, and indirect emissions. The Compendium includes calculation and estimation techniques for determining CO2 and CH4 emissions for sources within each of these categories. •

•

•

•

•

Combustion devices include both stationary sources, such as engines, boilers, heaters, and flares; and fleet-type transportation devices, such as trucks and ships, where these sources are essential to operations (i.e., material or personnel transportation). The CO2 emissions from these sources can be calculated from the amount and type of fuel they consume. Methane emissions, resulting from incomplete fuel combustion, are also a function of the amount and type of fuel consumed, as well as the efficiency of the equipment. Point sources include vents from oil and gas industry units, such as hydrogen plants and glycol dehydrators, that emit either CO2 and/or CH4. Point sources also include other stationary devices such as storage tanks, loading racks and similar equipment. The rate of these emissions is a function of the unit throughput and can be estimated by engineering calculation or by using appropriate emission factors. Non-point sources include fugitive emissions (equipment leaks), emissions from wastewater treatment facilities, and a variety of other emissions generated by waste handling. Non-routine activities, associated with maintenance or emergency operations, also may generate GHG emissions. The emission rates from non-routine activities are not easily determined and have to be evaluated on a case-by-case basis, often using a combination of factors and engineering calculations. Indirect emissions are defined as GHG emissions associated with oil and gas company operations, but physically occurring from sites or operations owned or operated by another organization. The Compendium specifically addresses purchased steam and electricity. Estimating these emissions requires input from the energy utility company or use of published emission factors based on average GHG emissions for energy generation in a given location or region.

Examining Emission Reductions API has reached out to governmental, non-governmental, and industry associations during the development of the Compendium to ensure broad peer-review and to create an approach consistent with the global oil and gas industry. This outreach effort continues with the current Compendium, available for distribution through API publications. Comments received will be used to improve the document in its next release (scheduled for early 2003). One aspect of particular interest to API is the use of the Compendium for estimating emissions associated with reduction projects. GHG emission reductions enhance not only environmental performance, but also economic performance, where reductions stem from improved energy efficiency or reduced CH4 emissions. Further understanding of the emissions reduction potential associated with such activities is valuable in promoting industry best practices. API is conducting a study to specifically evaluate the application of the Compendium to emission reduction projects.

GENERAL GUIDELINES FOR QUANTIFYING GHG EMISSION REDUCTIONS Determining GHG reductions associated with a specific activity requires the following steps: 1. Establish a reference case as the basis for comparison with the reduction project. 2. Identify and quantify the effects of the project, including direct and indirect emission increases and decreases. 3. Estimate emission reductions as the difference between the reference case and post-project emissions. The baseline for a project activity is the scenario that reasonably represents the anthropogenic emissions by sources of GHGs that would occur in the absence of the proposed project activity [2]. Due to certain complexities in project boundaries, such as energy imports or exports, the baseline scenario will not only

1027 include the activities conducted prior to the project (i.e., pre-project activities), but may need to reflect what would likely have occurred in the absence of the project. Each reduction project requires evaluation on a case-by-case basis to determine the most likely baseline scenario. Other technical issues encountered in considering emission reduction projects include: imported and/or exported energy; direct versus indirect affects of the project; the duration over which the emission reductions apply (i.e., permanence), and changes in baseline conditions. GHG EMISSION REDUCTION P R O J E C T CASE STUDIES An initial list of case studies was compiled based on input from the API workgroup members and other reported petroleum industry initiatives [3,4,5]. Seven specific projects were investigated, representing potential reduction opportunities of CO2 and/or CH4 emissions for different sectors of the petroleum industry. These example case studies were used to examine various technical issues associated with quantifying emission reductions and to illustrate the use of the Compendium. It is important to recognize that the reduction case studies selected may not be applicable to all locations and the emission estimates may not be representative of actual applications due to simplifying assumptions. Further details and illustrative estimates on three of the selected emission reduction case studies are presented in the following subsections.

Pneumatic Device Retrofit or Replacement Pneumatic devices use compressed gas as the motive force to perform process operations, such as controlling pressure, flow rate, temperature, or liquid level. Pneumatic devices operated with natural gas have been identified as a potentially significant source of CH4 emissions [6]. Some options for reducing emissions from pneumatic devices include maintenance, retrofit or replacement of the devices, and replacement of natural gas with compressed air. Potential emission reductions may be estimated for each of these various options using site data or measured pneumatic device gas consumption rates. Table 1 presents a summary of estimates for the scenarios examined as part of this case study example, using assumptions about the type and quantity of pneumatic devices associated with a hypothetical oil and gas production facility. Refinery Heater~Boiler Combustion Tuning Reductions in CO2 and CH4 emissions can be estimated based on reduced fuel consumption for heaters and boilers that have demonstrated improved efficiency due to combustion tuning. Combustion tuning approaches may include adjusting the burner air register settings to maintain uniform combustion air draft, adjusting the stack dampers to control air-to-fuel ratio, cleaning burner tips to remove carbon deposits or other blockages restricting air flow, and maintenance/repair of combustion system components. For the case study examined, an overall emission reduction of 3% was estimated, based on combustion tuning for 13 heaters and 2 boilers firing natural gas at a hypothetical refinery. Although actual results may vary, emission reductions for this case study ranged from less than 1% to 25% for individual combustion units. The methodology used to estimate emission reductions is based on techniques presented in the API Compendium. Cogeneration Emission reductions from cogeneration may result from an improvement in overall system efficiency compared to the separate generation of electricity and steam from conventional fossil fuel-fired boilers. For oil and gas industry operations, cogeneration provides potentially attractive energy efficiency and GHG reduction opportunities. Pre- and post-project direct emissions, thermal energy and electricity demands, and indirect energy imports and exports are all key baseline issues that must be addressed to determine cogeneration project reductions. Thorough characterization of displaced direct and indirect energy sources is also required. Finally, appropriate definitions of source and project operational boundaries must be developed to ensure that the cogeneration project reductions are credible and verifiable.

1028 The magnitude of GHG emission reductions from cogeneration is dependent on the form of generation being displaced, i.e., the baseline scenario for the specific project including both efficiency and fuel impacts. In cases where electricity is purchased from a local grid that represents mostly coal-fired generation, the overall GHG emission reductions from cogeneration may be substantial, due to both fuel carbon content and overall system efficiency differences. However, in cases where electricity is purchased in a geographic region of significant hydroelectric, renewable, and/or nuclear generation, emission reductions may be significantly lower, and in some cases could potentially result in a net increase in overall emissions resulting from the conversion to cogeneration. Three example case studies were developed to examine different scenarios and associated complexities that may need to be considered for a cogeneration project: • Cogeneration Case Study 1: A hypothetical greenfield cogeneration plant, developed primarily for independent power production, exports nearly all energy produced. For this example, the baseline emissions were approximated for an assumed "most likely" scenario in the absence of the project. For illustrative purposes, locally available electricity was selected to represent the baseline conditions, and emissions were estimated using electric grid emission factors for an assumed location. • Cogeneration Case Study 2: A hypothetical facility installs a cogeneration unit to improve overall efficiency. On-site energy use is assumed to remain essentially constant pre- and post-project, with excess energy sold offsite. This example examines exported energy and the complexities associated with determining emission reductions for increased efficiency. Two methods are presented for estimating baseline emissions: i) a grid displacement approach for exported electricity based on an assumed location; and ii) a comparison to natural gas-fired turbine combined cycle (NGCC), which was chosen to represent the "most likely" technology. • Cogeneration Case Study 3: On-site energy use post-project is assumed to increase due to organic growth over the pre-project case; excess electricity from the cogeneration plant is exportedto grid. For this situation, no clear, consistent rules on the methodology to establish the project baseline have been established. This example examines both a static baseline scenario with no adjustment for organic growth, and a dynamic baseline, representing on-site consumption rates after project start-up. For the static baseline scenario, post-project on-site energy use is equivalent to pre-project consumption. For the dynamic baseline scenario, baseline emissions associated with the incremental increase in on-site energy consumption are estimated assuming electricity supplied by the grid and steam generated by a natural gas fired turbine are the alternative energy sources in the absence of the project. For illustrative purposes only, estimated emissions for the various case study scenarios examined are summarized in Table 2. Emission estimates from combustion sources and electricity usage are based on calculation methodologies provided in the API Compendium. Again, it is important to recognize that actual results will vary for real applications due to site-specific conditions.

CONCLUSIONS Reductions in energy usage can result in reduced operating costs. Similarly, reduced CH4 emissions can translate into increased natural gas production/recovery. Due to the competitive business environment and pressure to control costs, oil and gas operators are taking steps to reduce energy usage and improve the efficiency of their operations. Demonstrating GHG emission reductions associated with these activities is an added benefit. This project quantified emission reductions for several oil and gas industry example case studies and provided insight into characterizing emission baselines and examining different reduction scenarios. Conclusions from this study include the following: • •

Specific emission reduction opportunities may not be applicable to all locations, and potential emission reductions will vary for each situation. Emission reductions require examining emissions from specific sources for the purpose of quantifying emissions before and after a reduction project has been implemented.

1029 • •

•

All emission sources that are likely to be influenced, either directly or indirectly, by a reduction project should be accounted for when considering the overall impact of the project on GHG emissions. Calculating emission reductions associated with energy imports and exports requires a project-by-project evaluation. Guidance for emission reduction reporting is beginning to evolve. Ultimately the selection of an appropriate approach depends on location-specific conditions, how the emission reductions will be used, any associated reporting specifications, and requirements of the host country and the buyer of emission reductions in the carbon market. Although the API Compendium was targeted toward developing emission inventories, which focus on the most significant emission sources and provide more general emission approaches for less significant sources, many of the methodologies are applicable to quantifying emission reductions. However, there are certain emission reduction projects, such as pneumatic devices, in which the estimation techniques provided by the Compendium do not provide sufficient detail for quantifying pre- and post-project emissions.

Enhancements to the Compendium to address these findings will be considered for the next release. (To obtain a copy of the current version see: www.global.his.com.) API welcomes a continuing open exchange of information and a broad discussion of GHG emission estimation methodologies. It is hoped that this process will achieve better harmonization of emission protocols and enable improved global comparability of emission estimates.

ACKNOWLEDGEMENTS

The authors would like to acknowledge the support and contributions of the API member companies in the development of the Compendium document. Company representatives on API's Greenhouse Gas Emissions Methodology Working Group have contributed valuable time and resources throughout the development process. We are particularly indebted to the companies that shared their internal company procedures and practices, and facilitated this process moving forward.

REFERENCES

American Petroleum Institute (2001). Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry; Pilot Test Version; API, Washington, D.C. [Mail Orders: API Publications c/o Global Engineering Documents, 15 Inverness Way East, Mail Stop C303B, Englewood, CO 80112-5776] United Nations Framework Convention on Climate Change (2002). Project Activity Design Requirements: Project Activity Baselines, CDM Modalities and Procedures, Annex Decision 17/CP.7, unfccc.int/cdm/baseline.html, Bonn, Germany. American Petroleum Institute (1999). Voluntary Actions by the Oil and Gas Industry to Address Climate Change, A Conference on Industry Best Practices, Houston, TX. Energy Information Administration (1996). Sector Specific Issues and Reporting Methodologies

Supporting the General Guidelines for the Voluntary Reporting of Greenhouse Gases Under Section 1605(b) of the Energy Policy Act of 1992, Volume 1, U.S. Department of Energy, Washington, D.C. U.S. Environmental Protection Agency (2002). Natural Gas STAR Program, Technical Support Documents, www.epa.gov/gasstar/tech.htm, Washington, D.C. Shires, T.M. and M.R. Harrison (1996). Methane Emissions from the Natural Gas Industry, Volume 12: Pneumatic Devices, Final Report, GRI-94/0257.29 and EPA-600/R-96-0801. Gas Research Institute and US Environmental Protection Agency, National Risk Management Research Laboratory, Research Triangle Park, NC.

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TABLE

l

SUMMARY OF EMISSION REDUCTIONS FROM PNEUMATIC DEVICE CASE STUDIES

Hypothetical Baseline Scenario l Oil and production operations with 20 liquid level controllers and 180 pressure controllers Baseline pneumatic device emissions, tonnes CO2 Eq. 23,444 Estimated % Emission Potential Reduction Scenarios Reduction a Improved maintenance 35% Replace high-bleed devices with low-bleed devices 93% Retrofit high-bleed devices to eliminate pilot bleed rate 99% 99.5% t) Replace natural gas with compressed air D Replace high-bleed devices with self-contained devices 100% a Note: percent reductions are based on assumed conditions for the example case study scenarios and may not be representative of actual reductions for real-world applications. b For this scenario, post project emissions are indirect due to electricity consumption, while baseline emissions are direct. Results in a 100% net decrease in direct emissions, and a 0.5% net increase in indirect emissions.

TABLE

2

SUMMARY OF EMISSION REDUCTIONS FROM COGENERATION CASE STUDIES

Scenario Description New cogen, plant consumes 1.556x1016 J (14,760,000 million BTU) of natural gas. Generates 1,523,000 MW-hr electricity and 1.404x10 is J (1,332,000 million BTU) steam. Cogen. requires 38,500 MW-hr electricity. Refinery purchases 206,000 MW-hr electricity. Burns 190,786 m3 (1,200,000 barrels) diesel to generate 2.857x101~ J (2,710,000 million BTU) steam for on-site use. New cogen, plant consumes 8.572x1015 J (8,131,500 million BTU) of natural gas to produce 1,100,600 MW-hr electricity and 3.810x10 is J (3,614,000 million BTU) steam. Refinery requires 2.857x1015 J (2,710,000 million BTU) steam and 244,500 MW-hr electricity. Excess energy is sold offsite. New cogen, plant consumes 8.572x1015 J (8,131,500 million BTU) of natural gas to produce 1,100,600 MW-hr electricity and 3.810x1015 (3,614,000 million BTU) steam. Refinery requires 3.810x10 is J (3,614,000 million BTU) steam and 313,500 MW-hr electricity. Excess energy is sold offsite.

Case Study

Greenfield Cogeneration Plant

Baseline Conditions (used for the following scenarios) Cogeneration Increased Efficiency Grid Replacement Approach c Cogeneration Increased Efficiency "Most Likely" Alternative Technology Approach d Cogeneration with Organic Growth - Static Baseline Cogeneration with Organic Growth - Dynamic Baseline e

Estimated % Emission Reduction a

43% b

(Baseline) 65% 63% 58% 56%

a Note: percent reductions are based on assumed conditions for the example case study scenarios and may not be representative of actual reductions for real-world applications. b Reduction estimates for the Greenfield plant are based on comparison with electric grid emissions for an assumed location. c The grid displacement approach is based on the average carbon intensity of power generation in the region or state (or country), projected over the lifetime of the project. The location was assumed for this scenario. d The "most likely" technology approach is based on recent projects and those projected to develop in the same relative timeframe. This approach is consistent with cited Clean Development Mechanism (CDM) methodology, i.e. "the average emissions of similar project activities undertaken in the previous five years, in similar social, economic, environmental and technological circumstances, and whose performance is among the top 20% of their category" [2]. Estimates for this example are based on electricity generated from a natural gas-fired combined cycle (NGCC) turbine. e Baseline emissions associated with the incremental increase in on-site energy consumption are estimated assuming electricity supplied by the grid and steam generated by a natural gas fired turbine are the alternative energy sources in the absence of the project.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

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CLEANER PRODUCTION TECHNOLOGY AND BANKABLE E N E R G Y E F F I C I E N C Y D R I V E S IN F E R T I L I Z E R I N D U S T R Y IN I N D I A TO M I N I M I S E G R E E N H O U S E GAS E M I S S I O N S - CASE S T U D Y Surendra Kumar FIE, Chartered Engineer (India) Head, PACD, Nuchem Weir Limited 119, LSC, Pocket D&E, Sarita Vihar, New Delhi -110044

ABSTRACT

The Fertilizer Industry offers a most exciting, challenging and rewarding opportunity for adopting Bankable Energy Efficient and Cleaner Production Technologies to support minimization of greenhouse gas emissions. Cleaner production technology has cut down energy consumption from 9 G. calories/Mt to around 7 G. calories/Mt in ammonia plants where capacity utilization has also improved from 74% to 84%. In addition, the Fertilizer Industry has initiated measures on waste heat recovery, reuse of heat in the plant system, and steam network system optimization through computer programming. Pneumatic controls have largely been replaced by distributed control systems mainly operated by electrical drives and recently, naphtha-based power stations have adopted the latest DCS systems resulting in 3-5% energy savings besides realizing 2-3% raw material saving and 2-2.5% enhancement in yield. Energy efficient technologies relevant to the Fertilizer Industry include fuel switching (exchanging fossil fuel based energy generation system with those that use renewable fuels like biomass, solar energy etc). This has resulted in zero greenhouse gas emissions and very low cost/unit of generation of power and steam. Efficient electric motors have replaced old designs of sets and an overall effort has been made to reduce heat and power losses, which finally results in less use of fuel, thereby minimizing emissions. Waste incineration has also become a source of energy recovery. The paper includes case studies to demonstrate substantial reduction in fuel consumption and reduction in greenhouse gas emissions through the adoption of cleaner technologies in the Fertilizer Industry.

INTRODUCTION

Indian population has exceeded 1000 million in May 2001, which necessitated a requirement to feed the population of 240 million tons, and fertilizer requirement of around 21 million tons. The increased demand for fertilizers required increased production and thereby increased atmospheric emission of pollutants and greenhouse gases. The Fertilizer Industry took up the challenge of increasing its outputs but not at the cost of environmental pollution. It adopted Bankable Energy Efficient and Cleaner Production Technologies to support minimization of pollutants and greenhouse gas emissions. Cleaner production technology has been able to cut down energy consumption from 9 G calories/Mt to around 7 G calories/Mt in present ammonia plants where capacity utilization has also improved from 74% to 84%. Focus on automation has helped to realize

1032 these objectives substantially. In addition, the Fertilizer Industry has initiated measures on waste heat recovery, reuse of heat in the plant system and steam network system optimization through computer programming. Energy efficient technologies relevant to the Fertilizer Industry include fuel switching (exchanging fossil fuel based energy generation system with those that use renewable fuels like biomass and solar energy). This has resulted in zero greenhouse gas emissions and very low cost/unit of generation of power and steam.

RELEVANCE OF CLEANER PRODUCTION IN F E R T I L I Z E R INDUSTRY The main emphasis of cleaner production in the fertilizer industry is to achieve better performance in existing and future fertilizer plants. The process improvements with reference to nitrogenous plants, which are using Naphtha or natural gas as feedstock material, are: 1. Improving yield from feed stock material. 2. Improving energy conservation. 3. Reduction in consumption of energy (energy consumption has come down from 9 G cal/MT to around 7.0 G Cal/MT in present ammonia plants). 4. Reducing emissions of liquid and gaseous effluents. 5. Operator friendly interface and acceptability. Three main groups of cleaner production technology i.e. source reduction, recycling and product modification, are the guiding principles in the fertilizer industry. Source reduction includes 'good housekeeping' and 'process changes'. Process changes include options on change in input material, better process control, equipment modification and technology change. Recycling is the on-site recovery and reuse of material and energy which otherwise comprises a waste. Product modifications are made to increase product lifetime to make recycling easier and/or to minimize the environmental impacts from the disposal of the products.

APPROACH OF INCORPORATING PROCESS IMPROVEMENT The steps for improving process performance are well addressed by adopting process automation at different levels in a fertilizer plant. Appropriate revamp/retrofit measures are being adopted in existing plants and new plants are likely to have in-built process automation. The approach could be one or several of the following measures: i) Installation of distributed control systems. ii) Heat recovery and steam net work systems to be optimized through computer program. iii) Pneumatic control systems being replaced by distributed control systems mainly operated by electrical signals. The equipment cost increases by 5% if process automation is adopted. The recent naptha-based thermal power stations at two fertilizers units have adopted latest DCS system. The incremental additional cost has been paid off within a year due to quantified benefits: 3 to 5% energy saving, 2 to 3% raw material saving and improvement in yield by 2 to 2.5%

CLEANER PRODUCTION AND ENERGY EFFICIENT T E C H N O L O G I E S RELEVANT TO F E R T I L I Z E R INDUSTRY

Fuel Switching (if technologically, locationally and adequately meeting the demand) The fertilizer industry is mostly based on natural solid, liquid or gaseous raw materials and does not afford high technology installations in steam and power generation, but can switch to biomass combustion in the boilers for co-generation of steam and power. Biomass such as rice husk, sirkunda, jungle grass, straw and other crop refuses can be very conveniently selected and burnt. The advantages include little or zero greenhouse gases and toxic emissions and no depletion of

1033 resources, as they are renewable sources of energy. The other advantages of using biomass as a renewable source of energy is the very low cost per unit of generation of steam and power, and also the easy availability in the nearby vicinity.

Captive & Co-generation P l a n t s - The solution Integrated energy services are emerging very forcefully world wide. Co-generation and combined heat and power (CHP) are gaining currency. Co-generation plants claim efficiencies of more than 85 percent compared with 35 to 55 percent for conventional power generation techniques. It is logical to strongly encourage captive and co-generation plants in India. Captive and co-generation plants in the fertilizer industry, especially based on biomass, add to process efficiency as well as reducing atmospheric emissions. Electrical and Utilities field There is a huge consumption of electricity by electric motors in all the areas in the fertilizer industry. 70% of the energy used in the sector is in the operation of electric motors. Even if there is a 1% improvement through taking control measures, there will be substantial savings of power in each unit. Similarly, use of energy efficient products such as transformers and industrial electronics capacitors, and provision of energy efficient lighting would result in large savings in electrical energy. The increasing cost of power naturally promotes the use of larger power cables, capacitors for power-factor correction, more efficient motors, generators, transformers, rectifiers and other power equipment to reduce energy losses. In the utilities section, the following major steps have been taken for energy conservation: 1. Proper selection of fuel firing equipment namely Burners, mechanical stokers etc. 2. Maintenance of correct temperature & pressure of fuel oil at the burner tip exactly as per manufacturer's specifications. 3. Minimising radiation losses from Burner, Furnace and auxiliary equipment by thermal insulation. 4. Reusing blow down and waste process heat to preheat the boiler feed water. 5. Control on loss of steam from Relief valves and other fittings by critical scrutiny of steam and power both at generation and transmission levels. 6. Use of calibrated meters for fuel consumption, steam generation and transmission to account for and control losses, if any. 7. Regular analysis of flue gases for optimising complete combustion and minimising wastages and heat losses. Estimation of CO2 and 02 in flue gases and operations stimulated through micro processed control with these parameters results in large savings. 8. Fuel combustion to maintain correct pressure of primary and secondary drafts to control unburnt fuel and/or heat loses. 9. Use of Deaerators, preheaters, Economisers and Recuperators for efficient reuse of waste heat. 10. Maintaining heat transfer surface area clean to avoid heat losses. 11. In case of coal firing, minimising unburnt carbon content in ash. 12. Adequate removal of condensate from pipe lines and reuse in Feed Water Circuit. Variable Speed Pumps Variable speed pump in place of M.C. Pump should be used. In these pumps control valves should be replaced with variable speed drives for efficient functioning to control flow rate of high concentration slurry. This minimises power consumption by about 26%.

CASE STUDIES - CLEANER TECHNOLOGY/ENERGY EFFICIENCY

Typical Success Stories of a Fertilizer Plant:

ii)

Unit No. 1 Production of Formic Acid Conservation of Waste gases generated in liquid nitrogen waste unit of ammonia plant into value-added product. Use of tail gas as boiler fuel

1034

iii) iv)

v)

Tail gas produced in ammonia plant and flared is used a fuel to main boilers. Use of waste CO2 for calcium ammonium nitrate production. Recovery and recycle at source Hydrolyzer stripper unit in the urea plant helps to eliminate liquid pollution cause by ammonia and urea, while recovering and recycling large quantities. For the Nitrophosphate Group of the plant, scrubbers have been provided where pollutants like ammonia, nitrous gases etc. are recovered and recycled. Also, closed underground tankers are provided where all leakages and spillages are collected separately in different sections and recycled to the process. Use of non-conventional sources of energy To reduce firewood consumption, the unit is actively promoting the use of nonconventional sources of energy like biogas, solar heating, windmills etc. in nearly villages. In fact, these systems have become very popular and more and more villages are now adopting these systems.

2. Unit No. 2 a) Conservation Measures By generating steam from process condensate the following benefits have been achieved: Water saving of 0.22 Million US Gallons/day. - Energy saving of 3.5 Million K.Cal/hr. - Elimination of about 0.4 MT of NH3 per day from final effluent stream. - Improved flexibility for auxilary boilers and DM Plant. - Improved overall reliability of plant operation. -

3. Unit No. 3 a) Conservation Measures Return and payback due to reduced raw material mainly from the NH3 recovery system, a section of the main plant project. It is capable of recovering 20-30 Kg. ammonia vapour per ton of CO product i.e. amounting to Rs. 25,000 per day resulting in pay back of capital investment for pollution control.

ENERGY CONSERVATION Measures, at a cost of Rs. 110 Lakh, have been commissioned which are capable of generating 2040 KWH by steam turbines, resulting in conservation of low pressure steam which is used in the process. PLANT DESIGN - BASED ON ENERGY CONSERVATION C R I T E R I A Energy Conservation in New Plants These have been selected to illustrate the application of sound engineering to the design of projects, with a comparison of construction and energy costs. They include: • Furnace efficiency • Power-recovery systems • Hydraulic-turbine power recovery • Reflux vs operating cost • Water cooling vs Air cooling • Fluid catalytic cracking unit power-recovery systems • Ammonia plant optimization • Ethylene-plant design • Cryogenic gas processing

The new ammonia process has changed the state of the art in several major respects: • The synthesis of ammonia is now being conducted at much lower pressure, approximately 150200 atm, compared to the prior practice of ammonia synthesis at 300 atm or more. • The new process is adapted to the use of low-cost centrifugal compressors, rather than the high cost reciprocating compressors previously used. The relative inefficiency of centrifugal

1035

• • •

compression is more than compensated for by the use of an efficiency energy cycle to provide steam turbine power. Previously unused "Water heat" is now recovered efficiently, and is used to provide the energy for gas compression. A highly efficient steam system has been developed to achieve a significant reduction in ammonia plant energy requirements. The refrigeration circuit is effectively utilized to liquefy and refrigerate the ammonia product.

Energy Conservation in Existing Plants • Side-draw distillation design reduced energy requirements by 50% over the first design. • Steam generation on the column condenser provided 2.5 kg/cm 2 steam for plant use its heat content is equivalent to that of the gas required for the fired-heater reboiler. • Burning the heavy stream in plant reduced net plant fuel gas requirements by about 5%. • A high-thermal-efficiency fired heater reduced by 25-30% the fuel gas requirement over conventional plant heaters. Efficient use of Steam One area of large potential savings is better utilization of steam. Whenever low-pressure steam is condensed by cooling water or air, roughly 2500 KL/kg of steam is wasted. To utilize this energy in low pressure steam, several of plants have replaced electric-motor-driven mechanical refrigeration units with absorption refrigeration units, which use 0.75 to 1.0 kg/cm 2 steam as the driving force. Previously, this steam was condensed from a 1 to 2 kg/cm 2 system and returned to the power plant as condensate. The net effect is to use the energy in the low pressure steam, thus saving electrical power. One plant has saved the equivalent of 20 million KJ/h in this manner, and several others have saved 2 -3 million KJ/h. More Ways to Save Steam In one plant, 35 kg/cm 2 steam was being throttled to 16.5 kg/cm 2 because the existing 16.5 kg/cm 2 system was supposed to be inadequate to provide the full requirement of such steam. The steam reducing station was shut down and the full requirement of 16.5 kg/cm 2 steam was made available. The pressure was slightly lower but adequate for requirements. This action resulted in a net savings of 15 million KJ/h. Another plant has several multistage steam jets for the evacuation of noncondensables and inerts from columns. It was found that these jets could handle the noncondensable load adequately with one less stage, so that final stage steam was turned off. This action saved over a quarter million KJ/h. This same plant found that it needed only a third to a half the amount of steam used in steam-tracing pipes and thus saved another 2 million KJ/h.

Condensate Recovery A plant recently completed a condensate-recovery project that involved the replacement of two barometric condensers (using cold seawater) on the final stage of two multijet vacuum systems. Approximately 230 kg/h of steam used in each of these systems was lost with the sea water in the condenser, along with minor quantities of a hydrocarbon solvent from the process. The barometric units were replaced by surface condensers, in which the steam condensate (containing the hydrocarbon) is kept separate from the sea water coolant and is collected in a decanter drum, where both condensate and hydrocarbon are recovered. This represents a modest savings of 130,000 KG/h of energy and eliminates a source of both thermal and hydrocarbon pollution. Minimizing Combustion Losses Another important area opted for energy savings is control of combustion. For a given stack temperature, the minimum heat losses occur with zero percent excess air (theoretically). However, the range of 0 to 5% excess air requires extremely good burner-performance. Power plant boilers incorporate economizers and combustion-air preheaters to reduce flue-gas heat losses.

1036 CONCLUSIONS In a very modest and humble way, the fertilizer industry in India is contributing towards efficiency and minimization of GHG emissions which, if adopted in other industries, definitely yield substantial savings. Fertilizer movement through co-operatives in India has given it a real thrust and a boost, with most of the units excelling in performance on a day basis.

REFERENCES

1. Techno Market Survey on Process Automation in Chemical, Textile & Fertilizer Industry. 2. Technology Information, Forecasting & Assessment Council (TIFAC) 1997. Dept. Of Science & Technology, New Delhi. 3. Chemical Weekly i. May 3, 1994 ii. August 25, 1998 iii. April 27, 1999 iv. Dec. 28, 1999 4. Sustainable Development by Enterprises - FICCI 5. Indian Industry Environmental Status Series - N o . - IV (Fertilizer Sector ) FICCI 6. Fertilizer Statistics- Fertilizer Association of India 7. N. Manivasakam, Industrial Effluent 8. Manual on Fertilizer M a n u f a c t u r e - Vincent Soucheble Davisopn Chemical Corporation 9. Energy Conservation Plant Design (Both New and Old) 10. Process Energy Conservation Richarg 11. Greeve & Staff of Chemical Engineer - 1992 12. Economic Times, July 2001

energy would further by day

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1037

COz REDUCTION IN THE IRONMAKING PROCESS BY WASTE RECYCLING AND BY-PRODUCT GAS CONVERSION J. Ct Kim and J.O. Choi RIST, Pohang Research Institute of Industrial Science and Technology San 32 Hyoja Dong, Pohang, 790-330 Korea

ABSTRACT In this study, recycling of the top gas of a blast furnace to its base, as a reducing agent, was investigated theoretically and some new concepts introduced. In particular, a new method for blast furnace top gas recycling using gasification of waste hydrocarbon material is suggested, and the characteristics of the system have been analyzed by thermodynamic calculation. By using coal or coke as a carbon source and blast furnace top gas as the gasification agent, a reducing gas is produced for iron ore containing 50% CO and 16% hydrogen, in the state of thermodynamic equilibrium at a temperature of 1000°C. With the ratio of effective (CO+H2) 0.112, this gas can be injected as a reducing agent directly into the blast furnace. For confirmation of this result practically, an experimental study on the gasification of waste hydrocarbon material e.g. waste plastic, low grade coal or organic sludge, and evaluation of the effects on the blast furnace operation will follow.

INTRODUCTION The Korean steel industry has about 50 years of history; this is a very short time period compared to the other major steel production countries worldwide. The real step of the Korean steel industry to a modern and large-scale industry started when Pohang Works started steel production in 1973, having an annual production capacity of one million tons. Crude steel production in Korea exceeded 10 million tons in 1981, 20 million tons in 1989, 40 million tons in t997 and maintained more or less the same level thereafter.

1038 Based on its yearly total production of 41 million tons, the Korean steel industry has increased production by a factor of about 280 during the last 30 years and shared 5.2% of the total steel production worldwide in 1999. The contribution of the Korean steel industry to the national product increased from 0.5% in 1970 to 4.6% in 1999. Moreover, the contribution of the steel industry to the total manufacturing industries in terms of product and to total exports were 6% and 5%, respectively in 1999. Considering the reduction of CO2 from an integrated steel work, the ironmaking process (the blast furnace, coke plant and sinter plant) would be the major target as about 75% of the total energy consumption is used in this process. Besides pulverized coal injection (PCI), hot reduction gases (HRG) are becoming alternative candidates that can reduce CO2 from blast furnace. The source of gas can be either an external gasifier or recycling of blast furnace gas (BFG) from which the CO2 is removed. In the course of this concept, a novel concept awaits to prove its ability to reduce CO2 using relatively easy operations and low cost. The concept is that a gasifier is used to produce a reducing gas for the blast furnace and BFG is recycled to the gasifier. Generally, it is expected that CO2 emission from the blast furnace can be reduced either by using H2-rich reduction gas or by reusing BFG after removing or reforming CO2 present. The main advantage of this system is expected to be that the unreacted reducing gas, CO and Hz in the blast furnace top gas is fed into the blast furnace by a circulation system and carbon dioxide in the top gas is converted in CO and used as reducing gas. In this work, the BFG recycling technologies are studied and the possible usages are suggested, as concluded from the predictive calculations. RECYCLING OF BLAST FURNACE TOP GAS Among the three major by-product gases in the steel works, coke oven gas (COG), blast furnace gas (BFG) and basic oxygen furnace gas (LDG), BFG is the major contributor to greenhouse emissions with approximately 70% of the total CO2 generation in the integrated steel works, if it is burnt in the works. BFG generation is estimated to be 1,500 m 3 per ton of crude steel. For this reason, the recovery of CO2 from the blast furnace gas is assumed to be most effective, and the following technical options for the reduction of CO2 emissions are suggested: •

Separation and sequestration of CO2 from the top gas

•

Recycling of top gas with or without CO2 separation

•

Integrated system with synthesis of chemical feedstock

Recycling of top gas with C02 separation Recycling of the blast furnace top gas after the CO2 separation has been studied theoretically as well as practically and has shown a productivity increase of 25% and a fuel rate decrease of 20% for the blast furnace process (1, 2).

It is possible to combine the existing blast furnace process with a methanol

synthesis process based on steam reforming of natural gas, which is well established in the chemical industry. A feasibility study of this process combination made clear the potential of energy savings and a reduction of CO2 emissions (3).

1039 The pressure swing adsorption (PSA) method is one of the most popular methods for CO2 separation. In the PSA process, the gas mixture flows through the beds at elevated pressure until the adsorption of the target gas approaches an equilibrium condition at the end of the bed. The flow of the gas mixture is then intercepted, the pressure is reduced and the adsorbed constituent is desorbed with a gas having low adsorptivity. The bed is then regenerated and is ready for the next adsorption cycle. For the PSA, therefore, two or more columns are installed for separation of the target gas continuously in a cycle.

Recycling of top gas without COz separation Recycling BFG as it is, still has an effect in reducing CO2 from the blast furnace. The gas produced from the blast furnace presently forms a reducing gas in the form of CO, and this can be reused by recycling the BFG as it is. However, in this case, the rate of reduction would be decreased, with the increased CO2 gas content in the reducing gas stream in the blast furnace. Even if pure oxygen is used to compensate for the heat loss by the increased CO2, certain precautions should be taken and experimental approval required before full application. Theoretical caculation results based on the foundry blast furnace are summarized in Table 1. In this calculation, only the equilibrium composition after reaction was considered and the whole mass and energy was balanced between input and output streams. All other conditions besides the BFG recycling are the same as that of the conventional operation (temperature, energy consumption for ore reduction, and compositions of raw materials). The results show that less coke would be needed than that required in the conventional operation and consequently, less CO2 emissions could be achieved. Because of the decrease of the coke production, fuel shortages are expected with repect to the overall energy balance for the integrated steel works and the use of natural gas (LNG) is recommended for the reduction of CO2. When 15% of the BFG from top of the blast furnace is recycled, the consumption can be reduced by 5.37% and overall reduction of CO2 would be expected if the LNG is used to compenaste for the fuel shortage. Because the equilibrium concentration of the product is linearly dependent on reactant concentration, the calculation result showed that the CO2 reduction is linearly proportional to the BFG recycle ratio. TABLE 1 EFFECT OF BFG RECYCLING

Amount [Nm3/tpi] 263.4

Rec, Ratio Coke Redctn.

[%]

[%]

Carbon Redctn.[%] BF Whole works

15

5.37

6,10

3,32

Recycling of top gas by means of waste gasification In order to investigate the BFG recycling without CO2 separation, a gasification process was tested in which various hydrocarbon sources such as low grade coal, waste plastics, or other organic waste material were gasified with BFG and oxygen. The product gas from the gasifier has higher carbon monoxide and

1040 hydrogen contents than the top gas, and is suitable for injection into the blast fumace as a reducing agent. Figure 1 shows the basic flow sheet of this recycling process. Thermodynamic calculations for coal gasification with BFG indicates that the equivalent amount of coal and oxygen are 20kg and 10Nm 3, respectively, for the conversion of lkmol BFG at 1000°C and 1atm down to the CO2 concentration of 5% as shown in Figure 2. The product gas has a composition of 73%

(CO+H2) and a heating value of 1,800kcal/Nm 3. If this gas is

injected into the blast furnace at a rate of 500Nma/thm, about 50 kg/thm of coke can be saved according to the formula of an "effective

(CO+H2)" (4). Filter

BFG

Crude COG

Carbon source Oxygen - -

Coke oven

Gasifier

Reformer

Figure 1: Top Gas Recycling with Reformer or Gasifier

'

0.6 -

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1

'

I

'

I

'

I

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,

i

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,

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,

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~

20

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25

o

30

Coal [kg/hr]

Figure 2: Thermodynamic Calculation of Coal Gasification with Blast Fumace Top Gas at 1000°C and 1atm Although the theoretical result shows the possibilities and potential, the feasibility of the process

1041 should be confirmed through experimental work as this is the novel process and no actual testing has been carried out. The experimental project should include: 1) a charging system that could handle waste shredder dust produced from automobile scrap and household appliances and industrial and municipal wastes including plastics, rubber, paper and other organic materials, with little preconditioning 2) a furnace design that secures the steady continuous operation including steady downward movement of the entire bed and discharge of ash in molten state 3) the controlling of the furnace temperature and addition of carbonaceous material that can provide heat and prevent agglomeration in the furnace 4) the confirmation of the possibility that CO2 will react with the gasification product gas 5) a gas handling system and the composition of the product gas 6) the effect of combustion gas (oxygen or air) 7) the granulation of the slag For this study, an experimental gasifier was designed and installed. The basic concept is that the gasifier is divided into two sections. In the first section, feedstock will be dried, and in the second section, the dried feed will go into the conventional gasification. Figure 3 shows the schematic diagram of the experimental set-up. In this furnace, a small part of the product gas is split from the main stream and is used for drying of the feed; the gas from the drying stage can either be recycled to the bottom of the gasifier or be put to some alternative use. The compositions of the dry and wet gas streams needs determining and the control of both streams investigated. Waste

&

Carbonaceous Additive

IS

Wet Gas

S

Recycling

]gent

I

Oxygen or Air with BFG

~ I-

Figure 3: Schematic diagram of gasifier, showing the concept of wet and dry gas production

1042 COKE OVEN GAS I N J E C T I O N TO THE BLAST FURNACE Here, the injection of the coke oven gas (COG) to the blast furnace as a reducing agent is considered. The calculation would be similar to that for the BFG recycle and the results are summarized in the Table 2. As is the case when the BFG is recycled directly, there is a linear proportionality between COG injection rate and the CO2 reduction. The effect of COG injection on the COz reduction is, however, not so promising as the BFG recycle as the major component of COG is hydrogen; this can be used as a fuel for many other facilities, and this in turn means that the carbon balance for whole works would not be improved, even if the COz emission from the blast furnace is reduced. TABLE 2 EFFECT OF COG INJECTION TO THE BLAST FURNACE

Amount [Nm3/tpi] 100

Coke Redctn. [%] 11,97

Carbon Redctn,[%] BF Whole works 8,1

1.93

DISCUSSION AND CONCLUSIONS Short term measures are applicable for the reduction of carbon dioxide emissions, independent of the energy input for separation and sequestration of CO2 from steel works gases. Pressure swing adsorption techniques can be applied for the separation of CO2 from the flue gas of the power plant and BF top gas. Chemical conversion and recycling of CO2-containing steel works gases can be also effective methods for the intensive use of the chemical constitutions of coal for iron making and thus, reduction of CO2 emissions. Various top gas recycling technologies look promising so far, but the practicability of these concepts is still in doubt; pilot or on-site tests will need much time and the confirmation of the contingencies still more. It is considered here that the key factor would be how we can get the sufficient data for oxygen enrichment technology to control the reaction in the blast furnace. REFERENCES 1.

ER. Austin, H. Nogami and J. Yagi, ISIJ International Vol. 38, No. 3, 1998, pp. 239-245

2.

M.A. Tseitlin, S.E. Lazutkin and CtM. Stiopin, ISIJ International. Vol. 34, No. 7, 1994, pp. 570-573

3.

T. Akiyama, H. Sato and A. Muramatsu, J. Yagi, ISIJ International. Vol. 33, No. 11, 1993, pp. 1136-

4.

P.C. Rhee, Journal of Korean Institute ofMetals Vol. 16, No. 2, 1978, pp. 115

1143

ZERO EMISSION P O W E R PLANTS

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1045

CLEAN COAL-FIRED POWER PLANT T E C H N O L O G Y TO ADDRESS CLIMATE CHANGE CONCERNS W.A. Campbell, Project Manager 1 and W.H. Richards 2 ~Canadian Clean Power Coalition, Suite 2304, 650 - 10th Street SW Calgary, AB, T2P 5G4, Canada 2 Nova Scotia Power Inc., PO 1609, Bras d'Or, NS B 1Y3Y6, Canada

ABSTRACT The Canadian Clean Power Coalition (CCPC), an association of Canadian coal and coal-fired electricity producers, has started on a detailed analysis of technology options to control air emissions, including CO2, which result from coal use. The goal of the project is to demonstrate that coal-fired electric power can be generated with emission levels similar to those from natural gas combined cycle, and to show that CO2 can be captured for commercial use or ultimate sequestration at a cost which does not render coal uneconomic. Initial engineering studies are underway, scheduled for completion in 2003, to evaluate technology options for both retrofit and new plants. Following the initial study phase, it is planned to proceed with two demonstration projects: the first for retrofit to an existing plant, is planned by 2007; the second for a new green-field plant, is planned to be carried out by 2010. INTRODUCTION The Canadian Clean Power Coalition 1 was formed in 2001 after discussions among Canadian utilities and coal companies revealed a common interest in proactive action to address the environmental concerns arising from the use of coal in electric power generation. In particular, concerns with the potential impact of air emissions on human health, and the growing concern with carbon dioxide emissions and their impact on climate, are issues that need to be addressed. Members of the CCPC, representing power generators and coal suppliers of over 90% of Canada's coal-fired power generation, believe that the need has never been greater for a demonstration of clean coal technology for power generation.

Emissions of Concern A growing awareness of the relationship between human health and air quality has focused environmental agencies to examine the role of coal-fired power generation as an emitter of various air pollutants of concern. In Canada and the United States, regulatory agencies are setting new ambient standards for ozone and fine particulate. In addition to its current program to drastically reduce NOx emissions in the 22 eastern States, the US Environmental Protection Agency recently Foundingmembersin 2001 wereATCOPowerCanadaLtd., EPCORUtilities Inc.,LuscarLtd.,NovaScotiaPowerInc.,Ontario PowerGenerationInc., SaskatchewanPowerCorporationand TransAltaUtilitiesCorporation.

1046 decided to regulate emissions of mercury from power plants. Canada has already introduced Canada-Wide Standards for mercury for incinerators and base metal smelting. A Canada-Wide Standard for Mercury emissions from coal-fired power plants is also under development. In 20012002 Canadian regulators began a review of the National Emission Guidelines for Thermal Electric Power Generation with an interest in controlling a diverse suite of emissions from the thermal electric power generation sector. Carbon Dioxide and Kyoto Protocol In addition to these issues, there is the as yet unresolved issue of CO2 emissions and how the goals of the Kyoto agreement, which the Canadian government recently expressed their intent to ratify, will be realized. Regulatory requirements for CO2 emission reductions by the thermal electric power generating sector appear inevitable. The principal concern raised by industry is with the potential for a series of separate, poorly coordinated emission control directives, each implemented to reduce a particular emission of concern, so that the cumulative impact is to render existing and future coal-fired power plants uneconomic. The CCPC believes that by addressing these issues in a proactive and comprehensive manner, the viability of coal utilization can be assured and that the economic benefits of doing so are significant for Canada. The goal of the project is to demonstrate technologies, for retrofit to existing plants or for use in new coal fired power plants, which will allow the full suite of emissions, including CO2, to be controlled to meet foreseeable regulatory requirements. The goal is to accomplish this while maintaining overall efficiency at or above current levels, maintaining costs competitive with other generation technologies, and enabling CO2 to be captured. This project will be completed by 2010 in several phases consisting of: • • •

Phase I - Conceptual Engineering & Feasibility Studies Phase I I - Retrofit Demonstration Project Construction & Operation Phase I I I - New Green-field Demonstration Project Construction & Operation

Coal Use for Power Generation in Canada Although hydro electricity provides the majority (61%) of electrical power in Canada (mainly in Quebec, Manitoba, B.C. and Ontario), coal-fired power generation provides 18% of Canada's power generation needs. Alberta, Saskatchewan and Nova Scotia all depend on coal for over 70% of their needs, with coal supplying 25% of Ontario's needs. It is expected that technology developed by the demonstration project could be applied to most coal-fired plants in Canada. It would be particularly of interest to coal-fired power producers in western Canada, where uses for captured CO2 are being demonstrated. The technology would also be of interest to coal users in the United States and overseas. The subjects of the Phase I studies are the coal-fired power plants in Alberta, Saskatchewan, Ontario, and Nova Scotia. Lignite, sub-bituminous and bituminous coals are being evaluated as feed stocks. The demonstration plants projected for the later phases of the project will most likely be located in westem Canada, where the CO2 produced can be sold for use in enhanced oil recovery projects. DEVELOPMENT PLAN Objectives The CCPC intends to construct two demonstration projects should the results of the preliminary research studies be positive. These demonstration projects would consist of:

1047 The retrofit of an existing plant with new technology to meet the environmental and economic goals outlined above, to be completed by 2007. The implementation schedule calls for project commitment in 2004, detailed engineering in 2005, construction from 2005 into 2007, and commissioning in 2007. 2. The design and construction of a new green-field plant to meet the environmental and economic goals outlined above, by 2010. The schedule for this is for project commitment by the end of 2004, engineering 2005 through 2006, construction from 2006 through 2008, and commissioning in 2009. 1.

Study Organization The overall project will be executed in a series of successive phases, with the initiation of each dependent on the successful completion of the preceding phase. Phase 1, conceptual engineering and economic feasibility, was initiated in August 2001. This project component is evaluating the range of developing technologies and will develop the conceptual engineering for application to power plants. The Management Committee of the CCPC has appointed a project manager to manage the activities of the CCPC and to carry out the overall work plan. A number of major subcontracts have been awarded, coveting the retrofit and new plant technology cases. The project manager is responsible for the overall co-ordination of all these activities and the preparation of the final reports. A Technical committee has also been formed to oversee the project and to ensure the work meets the goals of the CCPC and other stakeholders. The committee's management function is to review the overall progress of the work with regard to schedule and costs. In addition, this committee provides a general steering function in regard to the conduct of the work. PHASE I PROJECT W O R K PLAN

This phase is planned to be carried out over 2 years at a total cost of $5M CDN. The overall plan is shown below: Month Task

03

I o e l 09 I 12 I is I 18 121 I 24

2r

30

33

3e

Coordination Retrofit Em ission Control.Assessm ent Retrofit CO2 Control Options Assessment New Plant Technology Assessment New Plant Technology Selection CO2

Utilization

Assessment Final Report

IIl/u. •" m m , R I I r

w

~

Total

Cost:

$5,000,000

1048

Retrofit Case Study The main task in the retrofit case is to carry out process feasibility studies of technologies such as amine scrubbing, CO2/O2 combustion, and gasification. Evaluation of the latest R&D in process developments for scrubbing processes are being carried out, leading to the selection of the process to be used, and the conceptual design. A major issue is to determine the fate of all air emissions, as well as to assess other environmental impacts. Results from research carried out by the Natural Resources Canada CO2/O2 project at the CANMET Energy Technology Centre and at the International CO2 Extraction Test Centre project in Regina and at the Boundary Dam power plant of Saskatchewan Power are included in the studies. The design goals for the retrofit study are: a) no net loss of power output from the plant after retrofit; b) control and safe disposal of all emissions from the plant; c) capture of the CO2 from the plant and from any auxiliary power generation required; and d) evaluation of plant integration options and benefits.

Emissions Study In addition to this work, a separate study is being carried out to examine how all the emissions of concern, except CO2, can be controlled from an existing power plant. This component will evaluate the costs to control all air emissions except CO2 for a commercial scale retrofit. The design goals are: a) control ofNOx & SO2; b) control of particulates, including PM10 & PM2.5; and c) control of mercury and other air toxics. This knowledge then enables the net cost of CO2 removal to be determined by comparison with the process feasibility research studies that include all air emissions and CO2. This will provide a sounder basis for estimating the true additional costs for CO2 extraction in a regime where all other emissions must be controlled. Following completion of these studies, a decision will be made to select the technology to be used for the retrofit demonstration project as well as the site for the project. A proposal for the design and construction of a project to convert an existing power plant to demonstrate the retrofitting of the selected technology will be prepared.

New Plant Case With continuing high natural gas prices anticipated over the next few years, it is essential to develop and demonstrate new plant, advanced coal technologies that can meet all existing and anticipated environmental constraints. This part of the Phase I scope reviews available new plant technologies, selecting the most appropriate for use in a demonstration project. Technology options for new plant concepts have been reviewed in a pre-screening study in 2001. Technologies including supercritical pulverized coal, ultra-supercritical pulverized coal, pressurized fluidized bed combustion, integrated gasification combined cycles, and advanced gasification options were reviewed together with options to control all emissions, including CO2, down to low levels. Developing technologies, such as the Los Alamos National Laboratory's hydro-gasification with CO2 sequestration in serpentine mineral (being developed by the Zero Emission Coal Alliance, ZECA) were included, as well as other advanced gasification options. Based on the results of the technology review, detailed evaluations are being carried out to determine performance and costs allowing the best option to be selected for the new technology demonstration. Alternative sites for the demonstration are also being investigated and a preliminary assessment of the environmental issues is being carried out. The results of the studies will be summarized in a report that will recommend the technology and site to be used for the

1049 demonstration project. Candidate sites for a full-scale demonstration project will be evaluated and an implementation concept for the demonstration project developed.

C02 ManagementStudy Finally, altemative options for handling the CO2 extracted from the commercial scale and demonstration plants are being evaluated. Options include Enhanced Oil Recovery (EOR), Enhanced Coal-Bed Methane (ECBM) and sequestration in saline aquifers. This work is coordinated with other activities in western Canada on EOR and ECBM, with work in Nova Scotia on ECBM, and in Ontario on depleted oil reservoirs and aquifers. Measurement and monitoring requirements will be evaluated to ensure that amounts sequestered can be quantified. CO2 infrastructure requirements to make these options viable are being evaluated with regard to transportation, temporary storage, and recycling from EOR or ECBM projects. A final report will be prepared summarizing the work carried out. Candidate sites for a full-scale demonstration project will be evaluated and an implementation concept for the demonstration project developed, taking into account the plant's operational status and the need to minimize plant outages. PROJECT STATUS

As in most public-privately funded projects of this nature, considerable effort is required at the start to get the funding in place. This project is no exception, and much of the effort over the first year was in working with our federal and provincial energy departments in preparing proposals, discussing plans, and coordinating work plans. The project now has confirmed funding from the provinces of Alberta and Saskatchewan, and has confirmed federal support. All our private sector partners have confirmed their participation. Since project and organization inception many parties, national and international, have expressed interest in participating. CCPC has welcomed this interest and these additions. Both EPRI and IEA (through the Greenhouse Gas R&D programme and the Clean Coal Centre) have joined the CCPC in 2002 as full industrial participants. The initial study, to screen technology options for both retrofit and new technology cases, was completed in 2001 and terms of reference for detailed assessments of emission control technologies and evaluation of CO2 disposal options have been prepared and contracts awarded. It is expected that the detailed assessment of retrofit technologies will be completed by early 2003.

CONCLUSIONS Power generators using coal-fired generation see an array of new emissions regulations approaching in the next few years. There is an urgent need to understand and evaluate the ability for advanced combustion and emissions control technologies to mitigate the environmental impact of coalderived power generation before committing the significant capital investment necessary to construct the necessary plant. The Canadian Clean Power Coalition is one such response. The participants anticipate that the results of the studies just now being carried out will make a significant contribution to the understanding of the control of air emissions, including CO2, from the generation of power from coal.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1051

AN 865 M W LIGNITE FIRED CO2 FREE P O W E R P L A N T - A T E C H N I C A L FEASIBILITY STUDY

Klas Andersson 1, Henrik Birkestad 1, Peter Maksinen l, Filip Johnsson Lyngfelt 1

1, Lars Str6mberg l, 2, Anders

~Department of Energy Conversion, Chalmers University of Technology, SE-412 96 G6teborg, Sweden 2 Vattenfall AB, SE-162 87 Stockholm

ABSTRACT This work applies an O2/COa concept to commercial data from an 865 MWe lignite fired reference power plant and large air separation units (ASU). The aim of the study is to identify essential components and energy streams of the two processes and investigate the possibilities for process integration. A detailed design of the flue gas treatment before transportation of the separated carbon dioxide is also proposed. The sulphur dioxide can be sequestered together with the carbon dioxide, provided that the gas is dry, and, consequently, there is no need for a desulphurising unit. Since the investment cost of an ASU is slightly lower than for the desulphurising unit, the investment cost of the O2/CO2 plant will be slightly lower than for the reference plant. With all identified integration possibilities the net electrical efficiency becomes 34.3%, which is a reduction by 8.3 percent units compared to the reference plant.

INTRODUCTION Previous studies have shown that the O2/CO2 process is a competitive alternative for CO2 capture in power plants, e.g. [ 1]. O2/CO2 combustion involves burning the fuel in an atmosphere of oxygen and recycled flue gas instead of in air. The mixed flow of oxygen and recycled flue gas is fed to the boiler together with the fuel, which is burnt as in a conventional plant. Typically 70-80% of the flue gas is recycled from down stream the economizer and mixed with new oxygen. The remaining part of the flue gas is cleaned, compressed and later transported to storage or to another application. Studies on O2/CO2 combustion have mainly concerned emissions and combustion behaviour (e.g. [2], [3]) together with overall process studies (e.g. [4], [1]). Instead, this work combines a comprehensive study of the flue gas treatment together with integration possibilities of the O2/CO2 process, resulting in a proposal for an overall process layout (Figure 1). Thus, this work applies a lignite fired O2/CO2 combustion process to commercial process data in order to identify possible problems and to obtain design requirements under conditions as real as possible. Although an existing reference power plant forms the basis of the work, the purpose of this study is not primarily directed towards re-powering of existing power plants, but to identify limitations and possibilities for new O2/CO2 power plants. This paper gives a brief outline of the process obtained with details given elsewhere ([5], [6]).

METHOD The 2x865 MW lignite-fired Lippendorf power plant is used as reference in this study. This is a state of the art plant with a plant net (electrical) efficiency of 42.6% and with a district heating capacity of 2x115 MW. To minimize the need of redesign of burners, convection surfaces etc, an air like mixture of 20 vol.% oxygen and 80 vol.% recycled flue gas is chosen. This facilitates a direct comparison with the reference

1052

plant with respect to equipment and mass flows. Thus, for the O2/CO2 concept studied, the plant design and flue gas mass flow before recirculation are assumed identical with the reference plant, if not otherwise stated. Process data and schemes were obtained directly from the plant owner (VEAG). Based on these data, a process evaluation was carried out in order to identify new components needed as well as components that can be excluded for the O2/CO2 scheme. The process data of the ASU is taken from a plant, producing 50 000 mn 3 o x y g e n per hour, which was then scaled up with respect to investment costs and process data. Different compressor configurations for the ASU, as well as for the flue gas compression, were analyzed with Refcalc (Refrigerant Calculator) [7]. ChemCad (v5.0) [8], which uses electrolyte reactions together with a thermodynamic model, has been used to simulate the flue gas condensation. As a comparison to the latter calculations, and to determine the condensation energy, Hysys (v4.2) [9] was used. In the proposed scheme, NOx is separated in a liquid/gas separator since it assumed not to be soluble in CO2. RESULTS OF PROCESS EVALUATION Figure 1 gives a principal process scheme and component list of the lignite fired O2/CO2 plant as obtained from the process evaluation, using the Lippendorf reference plant. Thus, the three main parts of the plant are the ASU (A), the power plant (B) and the flue gas treatment pass (C) with the essential features and components described below following the numbering of Figure 1. :.............................................................................................................................................

I-1-3-1

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unit

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" 21. Subcooler '..-.~.'.'.'...~--.~---'.--.-'_.-..-'_'..-.'.ZZZZZZ33Z~Z~.~22. High pressure pump ~Oz [ ~ N

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.....

24. IP Steam turbine 25. LP Steam turbine 26. Condenser

r ~ ~

27. Cooling tower

02 :

r4]

% ~

.

(~

--

~

28. District heating 29. Feed water preheater 30. Feed water preheater 31. Optional heater, district heat 32. Nitrogen heater

Air inlet , ................................................................................................

l ~ ............................... J

Figure 1. Overall process layout for the O2/CO2 plant proposed in this work. The plant scheme is made with the Lippendorf plant as reference. A. Air separation unit, B. Power plant, C. Flue gas treatment pass.

1053

Air Separation Unit (A) The ASU is based on cryogenic air separation, which is the only separation technique which can provide the oxygen flows required in the present application [ 10]. The oxygen production rate in the plant is 451 100 mn3/h corresponding to an air flow through the compressor of 2 155 050 m,3/h. With an isentropic efficiency of 83% and with cooling provided from the plant cooling tower the power consumption of the compressor is 149 MW (tin=16°C, tout=22°C, year average). An oxygen purity of 95% is selected as the most favorable, since it gives an exchange rate (oxygen to oxygen) of 1.0 without nitrogen in the product gas. Thus, for oxygen purities lower than 95%, the oxygen contains nitrogen in addition to the impurity of argon. The compressor (1) in the ASU, with intercooling in four steps, operates between ambient temperature and about 60°C. Without intercooling an air temperature of about 210°C is obtained, giving a heat surplus of 140 MW, which could be used for feed water preheating or district heating. However, this would result in a significant decrease in compressor efficiency, corresponding to around 30 MW loss of power. Thus, this alternative is not chosen. The cooling of both the CO2 compressors (15) and (17) and the air compressor is carried out with cooling water from the plant cooling tower (27). The CO2 condensation also requires cooling water from the cooling tower, which means that the cooling capacity of these must increase with 25% compared to the reference plant. To minimize losses in power transmission to the air and CO2 compressors, these can be powered directly with steam turbines on a joint shaft. However, the main steam turbine shaft cannot be used for this purpose, since it would cause problems both in the compressor units, such as surge at the start up, and in the shaft itself because of too large thermal motions in axial direction. The extra investment cost of the separate powering of the compressors is to be compared with the power saving corresponding to about 6 MW. The heat required in the molecular sieves (5) are provided by the nitrogen heater (32), which exchanges heat from the flue gas with a minimum temperature of 200°C. Cooling, 20 MW of about 8°C, can be generated in the evaporative cooler (4) that can be used in the flue gas treatment for sub cooling of the carbon dioxide (21). Power Plant (B) Table 1 shows the mass and volume flows for the 865 MW O2/CO2 power plant. The flue gas temperature after the economizer (11) in the O2/CO2 power plant is assumed to be the same as for the reference plant; 340°C. The flame temperature in the O2/CO2 power plant will be lower than for conventional combustion with the given concentration of oxygen, 20 vol.%, because of the higher specific heating value of the flue gases compared to conventional combustion, [2]. On the other hand, the temperature decrease of the flue gas in the super heater and economizer will be lower than in the reference boiler, comparing the same steam flow as in the reference boiler. In addition to this, the radiative properties of the flue gas will change, which makes an accurate estimation of the flue gas temperature difficult. Still, the above assumption should be reasonable. Heat from the flue gas cooling and condensation, between 340°C and 20°C, can be used for feed water preheating and district heating, producing an extra power output of almost 16 MW and a heat surplus of 82 MW. TABLE 1. DESIGN COMPOSITIONOF FLUE GAS DURINGO2/CO2COMBUSTION Components

kg/s

wt%

H20 CO2 SO2 02

142.7 205.4 5.4 5.2 0.5 11.8 371.1

38.4 55.3 1.5 1.4 0.2 3.2 100

m3./s

vol%

179.8 105.3 1.9 3.7 0.4 6.7 297.8

60.4 35.4 0.6 1.2 0.2 2.2 100

_ .

N2 Ar Total

1054 Flue Gas Treatment Pass ( 0

The flue gas treatment basically involves the removal of water and non-condensable gases. Figure 2 shows the flue gas composition and emissions to air and sewer throughout the treatment steps. Each box displays the different gas emissions as weight percent of the total emission from each component. A complete dehydration of the flue gas is important since it will reduce the mass flow, inhibit corrosion and hydrate precipitation. If the flue gas is dehydrated to a dew point five degrees below the temperature required for transport conditions, the sulphur dioxide will behave almost as carbon dioxide and the two gases will not cause any corrosion problems. The gas must be dehydrated before reaching the high-pressure steps in the compression to make the compression of the gas mixture possible [11]. Carbon dioxide alone can be corrosive in the presence of water and cause sweet corrosion. What happens is that water vapour in the gas can form solid ice-like crystals called gas hydrates. The hydrates are formed when water "encages" gas molecules smaller than 1.0 nm (which is the case for both carbon dioxide and sulphur dioxide) at low temperatures and elevated pressures (below 25°C and above 15 bar). Various mechanisms for the carbon dioxide corrosion process have been proposed, which all involve either carbonic acid or bicarbonate ion formed when carbon dioxide is dissolved in water. Also in this case dehydration to a dew point five degrees below the transport temperature is sufficient to avoid the problem [12], since dry carbon dioxide is not corrosive at temperatures below 400°C [ 13]. The maximum water content in the gas prior to compression should therefore not exceed 60 to 100 mg/m3, [ 14]. A general rule for pipeline transportation in presence of water is that serious corrosion can be expected if the partial pressure of carbon dioxide exceeds 2 bar [ 15]. In the process chosen the gas is dehydrated in two steps. The first is in a traditional flue gas condenser (13) where most of the water is removed, together with remaining particles (sulphur trioxide etc). The second dehydration step is the Tri Ethylene Glycol (TEG) unit (16), which will remove the remaining water down to a value of 60 mg/m3n, corresponding to a dew point of-5°C at 100 bar in the transmission gas.

Jkg/h

io,~

kg/h

Iwt% I

1739578 1~,61

wt%

kg/h

wW,

kwh

kg/h

wt%

wt%

~

735,,, 00,~,

~

7~,12,133

~

7~195,135

~

7~5,770

ISO= 119513 11.471

iso 2

16967 2.07

so 2

16593 2.05

so I

16588 2.65

so 2

16586 2.21

i.,0

=,20

8787 10,

.,0

2~

oo3

.20

24

~0

24

0.26

N=+NO 2083 ~1

151~, p.,31

IN2+NOI2083

......... 102

I"

1~2

10.18 ]

141'~' 1°,71 I

Irot~ 11~59521

!

N2+NO12083 0,25

13.15 ~...... 02

1~2

Ni+NO 2083

5.11 ................... 02

~1

,,

~417~, 1.15

,,

Tot~

817817

TOt= 8 0 ~ 5

i

i

'

°

. . . . ."

0.~

5,17 ............ o,

41,8, 118

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~,

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Tot=

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' I

.. . . . . . . . . . . . . . . . . . . . .. . .. . .. . ... ... . .. . .. . ... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

.."

".. . . . . t .

~2~ '~---~

Removed from Flue Gas Stream:

kg/h wt% C~ 782 0,15 SOz 2546 0.50 H20 504807 99,35 Nz'H~C)0 10,00 02 0 ,0,00 A.," 0 0,00 Total 508135

kg~l CO~ 382 SOz 374 H=O 8535 N2+NO10 Oz l0 A,," I0 Total 9291

To Sewer

To Sewer

wt% 4,11 4,03 91,86 0,00 0,00 0.00

o~

N2+NO 0 0.00 0 0.00 ...... ,"'- ht 0 0,00 "" " ' Total 751195

02

kg/h C.~ 217 SOz 5 I"~O 228 N2+NO 0 02 0 Ar 0 Total 450 To Atmosphere

wW, 48,22 1,11 50,67i 0,00 0,00 0,00

..

. .........

kg/h CO~ 3610 SO= 2 HzO 0 Nz,H~IO2083 Oz 9401 Ar 41784 Total 56880

wt% 6.35 0,00 0,00 3,66 16,53 73,46

To Atmosphere

Figure 2. Mass flows [kg/h] and concentrations (weight percent of the total emission from each component) through the flue gas treatment steps.

1055 Since the TEG requires a pressure of 30 bar to be efficient, a compressor step with intercooling is installed before the TEG. Some water is separated in the cooling steps in the compressor. To reduce the power consumption of the flue gas compressors, compression up to the transport pressure is carried out by a high pressure pump (22). This, since the pressure should only be increased sufficiently to transfer the flue gas (mostly carbon dioxide) into a liquid state at a reasonable cost. The first compressor step raises the pressure from 1 bar to 30 bar, which is the inlet pressure of the TEG. The flue gas is then compressed in the second step from 30 bar to 58 bar. At a pressure of 58 bar, the carbon dioxide and sulphur dioxide will, if cooled to 20°C, liquefy and 20°C is the temperature of the main cooling system. When the carbon dioxide is liquefied it is possible to use a high pressure pump for the last pressure raise up to 100 bar before transportation to the injection site.

PLANT E F F I C I E N C Y AND

EMISSIONS

Figure 3 shows a sankey diagram illustrating the energy losses in the O2/CO2 plant based on one of the blocks (865 MW) of the reference plant. The net electrical efficiency of the plant becomes 34.3%. An extra heat production of 82 MW per block, not included in the sankey, is a product from the flue gas condensation, which could be used in the existing district heating system of 115 MW per block.

- -

B;il026Power MW

~ ~"~'~

Internalelectricity dmd

\\ ~ . . ~ C02 compression \ """'ASU 71 MW-3.5% [ 137MW - 6.7%

~1 ~z

Figure 3.

-~--~

]~ Powerproduction \ 696 MW - 34.3% / without losses - 933MW /extra power output - 16 MW ] / e x t r a heat production - 82 MW

j'/

Condenser 1093MW - 54.0%

Sankey diagram of the O2/CO2power process.

Table 2 summarizes emissions to air from the O2/CO2-fired plant obtained in the present study and compares these with those of the reference plant. The combustion conditions are considered to be stoichiometric with an oxygen excess of 1.5% on a dry basis. The SOx and CO2 emissions are leakage flows from (13), (16) and (20) in the flue gas treatment as shown in Figure 2. Estimation on NOx formation is based on the results in [2]. NOx is emitted in the gas/liquid separator (20) since it is not soluble in the CO2/SO2 mixture. It should be noted that the emitted NOx has a considerably high concentration. To attain even lower NOx emissions this component arrangement could therefore be well suited for a NOx catalyst. Total emissions [kg/h] are calculated for 2x865 MW, corresponding to both blocks of the reference plant. TABLE 2. COMPARISON OF ESTIMATED EMISSIONSTO THE ATMOSPHERE BETWEEN THE REFERENCE PLANT AND THE O2/CO2 POWER PLANT Emissions to air

SOx NOx CO2 Dust

Reference plant < 350 mg/mn 3 < 145 mg/mr, 3 < 235 g / m , 3 < 2 m g / m . :~

< 2,230 kg/h < 920 kg/h < 1,480 tonnes/h < 12 kg/h

[

O2/CO2-plant < 6 mg/mn 3 < 141 mg/mn 3 < 4 g/m, 3 < 1 mg/mn 3

< 20 kg/h < 310 kg/h < 8 tonnes/h < 1 kg/h

1056 CONCLUSIONS This study proposes an overall process scheme of an 02/C02 plant (Figure 1) based on commercial data from existing plants. With all integration possibilities considered the net electrical efficiency becomes 34.3% which corresponds to a decrease by 8.3 percent units compared to the reference plant. The O2/CO2 plant can be considered as a more or less zero emission concept (Table 2). An almost complete dehydration of the flue gas is of great importance to avoid problems in the final flue gas treatment and in the transportation of the carbon dioxide. The investment costs of the flue gas treatment are lower than in the conventional case, mainly because there is no need for a desulphurising unit. Summing up the extra cost for the ASU and the extra cooling capacity needed (25% larger) the investment cost becomes approximately the same for the O2/CO~ plant as for the reference plant. In conclusion, by using commercial data from existing plants and components this study shows that 02/C02 combustion is a realistic and a near future option for CO2 reductions in the power sector with an avoidance cost of approximately $8 per tonne CO2 excluding transportation and injection costs. Cost data are taken from [5] and [6] with the lignite price set to $0.0040/kWh.

ACKNOWLEDGEMENT

This work was financed by the Swedish National Board for Energy Administration and Vattenfall AB. The supply of data by AGA and VEAG is greatly acknowledged.

REFERENCES

1.

2. 3. 4.

5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15.

Singh, D.J. et al. (2001) C02 Capture Options for an Existing Coal Fired Power Plant: Oe/COe recycle Combustion vs. Amine scrubbing. Presented at the first national conference on carbon sequestration. Washington, USA. Croiset, E., Tambimuthu K. and Palmer, A. (2000) Coal Combustion in O2/CO2 Mixtures Comparison with Air. Canadian Journal of Chemical Engineering. Vol.78, p 402-407. Kimura et al. (1995) The Characteristics of Pulverized Coal Combustion in 02/C02 Mixtures for CO2 Recovery. Energy Conversion Mgmt Vol. 36 No 6-9, p.805-808. Bolland, O. and Undrum, H. (1998) Removal of COefrom Gas Turbine Power Plants: Evaluation of Pre- and Postcombustion Methods, presented at the Fourth international Conference on Greenhouse Gas Control Technologies, Interlaken, Switzerland. Andersson, K. and Maksinen, P. (2002) Process Evaluation of C02 free Combustion in an Oe/C02 Power Plant, MSc Thesis, Chalmers University of Technology. Birkestad, H. (2002) Separation and Compression of C02 in an Oe/COe-fired Power Plant, MSc Thesis, Chalmers University of Technology. Refrigeration Utilities, Technical University of Denmark, 2000. ChemCad (v5.0), Chemstations Inc., Texas, USA. Hysys plant (v4.2), Hyprotech Ltd., Alberta, Canada. K~llstr6m, M. AGA, Private communication on cryogenic air separation process. Lindeberg, E. IKU Petroleum Research, Private communication on behavior of CO2 and SO2 mixtures. Fayed, A. (1983) COe Injection for Enhanced Oil Recovery Benefits from Improved Technology. Oil&Gas Journal p. 92-96. Kermani, M.B. and Smith, L.M. (1997) COE Corrosion Control in Oil and Gas Production. European federation of corrosion publication No. 23. London: The institution of materials. Sloan, E.D. (1998) Clathrate Hydrates of Natural Gases. Marcel Drekker Inc. New York, USA. Berry, W. (1983) How Carbon Dioxide Affects Corrosion of Pipeline. Oil&Gas Journal. March 21, p. 160-163.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1057

RECENT DEVELOPMENTS ON FLUE GAS CO2 RECOVERY TECHNOLOGY Tomio Mimura 1), Takashi Nojo 1), Masaki Iijima z), Takashi Yoshiyama 3), Hiroshi Tanaka 3) 1) Technical Research Center, The Kansai Electric Power Co., Inc. 11-20 Nakoji 3-chome, Amagasaki, Hyogo 661-0974, Japan 2) Mitsubishi Heavy Industries, Ltd. 3-1, Minatomirai 3-chome, Nishi-ku, Yokohama, Kanagawa 220-8401, Japan 3) Hiroshima Research & Development Center, Mitsubishi Heavy Industries, Ltd. 6-22, Kan-non-shinmachi 4-chome, Nishi-ku, Hiroshima 733-8553, Japan

ABSTRACT The Kansai Electric Power Co. Inc., and Mitsubishi Heavy Industries, Ltd. have been making continuous efforts to improve flue gas CO2 recovery technology. The recent improvements have been focused on the reduction of the initial costs and operation costs. The following are the recent main research and development items: • • •

Increase of flue gas velocity in the CO2 Absorber Reduction of the KP-1 packing weight Reduction of amine consumption

These items have been put to the test in the Nanko Power Station pilot plant and their performances have been confirmed. In addition to the above, development on new energy efficient solvents has been carried out. A new bench scale testing facility enabled very accurate measurement of the CO2 recovery energy consumption to be made; this was the same as that of the pilot plant and was used for the evaluation of new solvents. INTRODUCTION The Kansai Electric Power Co. (KEPCO) and Mitsubishi Heavy Industries, Ltd. (MHI) have been carrying out joint work on research and development of new technology for CO2 recovery from power plant boiler flue gas and gas turbine exhaust gas. From the results of this research and development work, an energy efficient solvent was developed and commercialized. The first commercial plant using this solvent has been operated since October 1999 in Malaysia. The performances of the commercial plant was disclosed in GHGT-5 in Australia. l) The recent research and development activities since the GHGT-5 disclosure are described in this paper.

1058

High Flue Gas Velocity Tests in the C02 Absorber KEPCO and MHI have jointly developed the KP-1 packing which has very low pressure loss under atmospheric flue gas conditions and very high gas and liquid contact efficiency. The Nanko power plant flue gas CO2 recovery pilot plant is designed to operate with 555 Nm3/H flue gas flow rate at the inlet of CO2 absorber. KP-1 is designed with a packing diameter of 320 mm and has under the normal operating conditions a flue gas velocity of 1.92 Nm/s and a pressure loss of 40 mm H20 through the CO2 absorption part (KP-1 packing part). KEPCO and MHI carried out higher flue gas velocity tests with the maximum allowable flue gas velocity of the existing pilot plant. A maximum flow rate of 950 Nm3/H was obtained at the inlet of the CO2 absorber and under this condition, the flue gas velocity at the inlet of CO2 absorber packing (KP-1) was 3.29 Nm/s. Stable operation with stable performance was confirmed under the 950 Nm3/H flue gas flow rate and no flooding was observed. Therefore, it is considered that for KP-1 packing, the flue gas velocity can be increased to more than 3.3 Nrn/s. The plant for this year is to replace the flue gas blower with a larger one and conduct higher flue gas velocity tests up to 4.0 Nm/s at the KP-1 packing inlet. Figure 1 shows the pressure loss through the CO2 absorber, under various flue gas velocities.

1000

< E r~ O

.1

• 100

10 ~ 100

I

/~ CO2 Absorption Part Pressure Loss

|

1000 Flue Gas Velocity (Nm3/H)

CO2 Absorber Total Pressure Loss

10000

Figure 1:CO2 Absorber Pressure Loss

1059 Figure 2 shows C02 recovery energy dependent upon flue gas velocity at a C02 content in flue gas of 6.0 vol.%. Using this pilot plant operational data, C02 recovery energy or C02 absorption efficiency was not affected by flue gas velocity in the C02 absorber. ©

1000 900 800 | | I

i

700

! | |

g d

600

d

500

. . . . . . . .

t. . . . . . . . !

,~ . . . . . . . . ! | !

2

1

3

4

CO2Absorber Outlet Flue Gas Velocity(m/s) Figure 2:CO2 Recovery Energy New KP-1 Packing The KP-1 packing is ideally shaped for contact with flue gas under atmospheric conditions and liquid (solvent) flow in parallel. Due to this shape, flue gas pressure loss through KP-1 is very low and therefore the flue gas velocity can be increased with a reduction of CO2 absorber tower diameter at the same time. The test results of KP-1 packing were disclosed in ICCDR-2 held in Kyoto 1994. However, as the price of tower packings, such as random packing and structure packing, have been reduced recently, the KP-1 packing has to compete with these conventional packing on a cost base. Therefore, efforts to reduce the weight and number of parts of the packing in order to compete with conventional packing have been made, and as a result, the new KP-1 packing has been developed, composed of an uneven surface lattice plate structure, similar to KP- 1 packing. The new KP-1 was manufactured and installed in the Nanko pilot plant and subjected to the performance tests. The test results of the new KP-1 packing was similar to the previous KP-1 packing in terms of C02 absorption efficiency and pressure loss through the packing. Please refer to Figure-3. • : PreviousKP-1 Packing O : NewKP-1 Packing 00 ~-~ .o

80 60 40

8

20 0 0

50

100

150

200

Steam Flow Rate [kg/h]

Figure 3"

CO2 Absorption Efficiency of previous KP-1 Packing and New KP-1 Packing

1060 A study is now being made for the mass manufacturing of the new KP-1 packing in order to compete with the cost of the conventional packing.

Reduction in Amine Consumption For CO2 recovery from atmospheric flue gas with the chemical absorption method, amine loss is relatively large. In the case of monoethanol amine (MEA), amine consumption is usually as much as 2kg/Ton CO2 recovered. The reasons for high amine consumption by the MEA process are high degradation of MEA by itself and high outflow of MEA from CO2 absorber. KEPCO and MHI have developed the KS-1 solvent which is already applied for commercial use and its amine consumption is around 0.35 kg/Ton CO2 recovered. This consumption is about 1/6 of the MEA solvent, however, it is still high compared with the high-pressure natural gas or synthesis gas CO2 removal processes. From detailed investigations into the causes of amine losses, it was understood that a combination of decomposition, vapor loss and mist loss were responsible. Therefore, various mechanical devices and operational conditions were tested that resulted in reduced amine consumption of about 0.1--0.2 kg/Ton CO2 recovered.

TABLE 1 AMINE LOSS DEPEND UPON FLUE GAS TEMPERATURE WITH SPECIAL MECHANICAL DEVICES Absorber Inlet Temperature

Average Amine Loss

35 (°C)

0.06 (kg/Ton CO2)

40 (°C)

0.16 (kg/Ton CO2)

46 (°C)

0.20 (kg/Ton CO2)

New Bench Scale Test Facility In order to evaluate new solvents quickly and accurately for flue gas CO2 recovery, a new bench scale test facility was designed and constructed in KEPCO Technical Research Center. The main specifications are indicated in Table 2. TABLE 2 SPECIFICATION OF BENCH SCALE TEST FACILITY Gas flow rate

Max. 7 m3/h

Liquid flow rate

Max. 30x10 -3 m3/h

Absorber height

2.3 m x 2 Tower (series)

Absorber I.D.

100 mm

Stripper height

1.8 m

Stripper I.D.

100 mm

Washing water tower height

0.5 m

Washing water tower I.D.

100 mm

Unit Size

4.7 m L x 1.4mw x 2.5mH

1061 Although the capacity of this bench scale test facility is small, the C02 absorption and stripping efficiencies are designed to be the same as that of the Nanko Power station pilot plant; this was accomplished through the installation of special heat traces to minimize the heat loss. Details are shown in Figure-4. Insulation

Stripper Shell

Copper Plate ~ _ .

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

Heat Trace/ / V / / , Q / / / / ~ Insulation/

/

Iron Cover P l a i ! /

Figure 4: Stripping Tower Heat Trace Due to the installation of the above-shown heat trace, CO2 recovery energy requirements of the bench scale test facility is the same as that of the pilot plant test results. By using this bench scale test facility, evaluation tests of the new solvents can be made accurately and speedily. REFERENCES 1)

Mimura T., et al. 2000 Greenhouse Gas Control Technologies, Caims Australia P. 138--142.

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1063

I G C C - THE BEST CHOICE FOR PRODUCING LOW-COz POWER G. Haupt ~, G. Zimmermann ~, R. Pruschek 2 and G. Oeljeklaus3 Siemens AG Power Generation, 91050 Erlangen, Germany 2 Independent Consultant, 70839 Gerlingen, Germany 3 University of Essen, 45141 Essen, Germany

ABSTRACT This paper reports the results of two comprehensive studies on CO2 reduction measures using integrated gasification combined cycle (IGCC) technology. The first part deals with reduced CO2 production by efficient use of energy resulting in an advanced coal-based IGCC concept with 51.5 % net efficiency (LHV). The second part provides IGCC solutions to reduce the CO2 emission to the atmosphere via CO shift and CO2 separation followed by coproduction of methanol/synthetic gasoline as an interim disposal option. An economic analysis ends up with acceptable 6 %age points efficiency loss due to CO2 removal and production costs for the liquid transportation fuels around present gasoline market prices including tax.

INTRODUCTION

: : : :: ~:i'¸::i~.... ~: .... ~ l t t t l l l l n m ~ l L ~ t ~ ~ ~

:

: :

]

~

~~oital~Of Oi|Fields: ~ :'C~mi~llndustryI ::

Figure 1: Potential steps for C02 reduction In view of recent and future developments in the field of IGCC power plants expressed by increasing overall efficiencies, a significant CO2 emissions reduction becomes possible solely by replacing old and low-efficient pulverized-coal-fired (PCF) power stations with advanced IGCC plants. If CO2 emission has to be reduced by 60 or even 80 % and coal has to be used under such circumstances, an extensive separation

1064 of CO2 from the power plant process could be of increasing importance as an option. However, any CO2 removal measure will unavoidably and significantly reduce the station efficiency and power output. Figure 1 provides some kind of systematic overview of measures, methods to verify them and disposal strategies. STATUS OF THE ADVANCED IGCC POWER PLANT IGCC technology must be measured against the most advanced PCF power stations. A plant of this type with a design efficiency of 47 % has been commissioned by ELSAMPROJEKT in Aalborg/Denmark (Nordjyllandsvaerket), on which the ambient conditions for this study are based. The coal selected is Pittsburgh No. 8, a typical imported hard coal which can be readily gasified. With a target efficiency of considerably more than 50 %, it is assumed that the power plant will be operated primarily at base load. The plant is designed in a single train and has a capacity of roughly 450 MW, corresponding to the gas turbine-generator used. The primary design objective is efficient operation with coal. Operation with natural gas as a secondary fuel, especially for start-up, plays only a secondary role with regard to efficiency. Figure 2 shows a simplified flowsheet of the advanced IGCC concept as a result of plant optimization:

co~

' ~

i~ P , ~ . o .

Ii Ii

T ........ ' ~ - ~-~ ~ i ~ Turbine I I

III

Ill "-" "r,.,

w

Saturato HP _ ~ Reheat. \

Gasifier

\ ,

I Slag

- i 1 ~ , ~ ~ - [ , , o ,•

" I~Cl~n~'~

QuenChWas~e~ w.... Gas Treatment

r~

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,,

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Saturationl J

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r S,oa~ I r

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J

I~°'n"P-~

(~ (~ Cond22s I (~ (~I (~BFT'WlTank~t~ O2 N2 HeatR..... ryl Z~ / ~ ' ate

I

Figure 2: Advanced IGCC plant based on a Siemens Model V94.3A gas turbine-generator Table 1 gives an overview of significant plant data including overall efficiency. Nearly two thirds of auxiliary electric power requirement is accounted for by gas generation. Primary loads are the compressors for the main products from air separation unit (ASU), particularly for the Nz fraction. Further significant auxiliary loads are the main feedwater pumps. The performance of the advanced IGCC concept includes a significant reduction of gaseous emissions and solid byproducts compared with today's most advanced PCF power plants, in particular compared with a standard PC boiler, based on the same coal. The emission of CO2, for instance, is reduced by approx. 10 %, and even by approx. 25 % for standard PC boilers showing efficiencies in the range of 38-40 %. A specific capital investment ofUS$1,100/kW results for the advanced IGCC power station from bidding information prepared by involved manufacturers. This reasonable price level could be achieved through the tremendous increase in net power output with nearly the same absolute capital investment as for IGCC plants designed previously. Based on the advanced IGCC plant efficiency of 51.5 % determined in this development potential study, levelised electricity generating costs of 46 mills/kWh as a typical value result, which are approx. 10 % less than with today's most advanced PCF steam power plants, if a fuel price of

1065

US$1.5/GJ (LHV) and 6,500 full-load hours/yr are assumed. In the future, the specific capital investment of IGCC plants optimised further could break the US$1,000/kW barrier [ 1]. TABLE 1 SALIENT DATA RESULTING FROM OVERALL CYCLE CALCULATIONS Heat input (LHV): Coal (2545 tpd) Natural gas (for coal preparation) Total Gross power output: Gas turboset Steam turboset Total Gross efficiency (LHV) Power consumption: Gas island Combined cycle General facilities Total Net power output Net efficiency (LHV)

874.8 MJ/s 0.9 MJ/s 875.7 MJ/s 302.3 MW 177.3 MW 479.6 MW 54.8 % 19.9 MW

7.9 MW 1.0 MW 28.8 MW 450.8 MW 51.5 %

I G C C S T A T I O N S W I T H CO2 R E M O V A L If CO2 reductions solely based on efficiency improvement measures as mentioned above are not sufficient, CO2 can be removed to a great extent and very effectively from IGCC stations. A pre-basic design was prepared in a preceding study including a water gas shift reactor system which is able to convert CO and H20 into CO2 and H2. Sulfur compounds as well as CO2 can then be removed simultaneously, for instance by Rectisol wash. With regard to economic aspects, around 90 % of CO2 are removed and extracted as a gas slightly beyond atmospheric pressure which results in 6 %age points lower net efficiency and 10 % higher investment. Table 2 compares salient data of the IGCC station with CO2 removal and a conventional IGCC plant as reference case: TABLE 2 SALIENT DATA OF THE REFERENCE CASE AND THE IGCC STATION WITH

CO2 emission (stack) absolute specific Coal heat input Gross power output gas turbine steam turbine Auxiliary power requirement Share of gas treatment Net power output Net efficiency

Reference case 72.9 kg/s 0.69 kg/kWh 811.2 MJ/s 238.8 MW 177.7 MW 37.8 MW 3 % 378.6 MW 46.7 %

C02 REMOVAL

With CO2 removal 8.4 kg/s 0.09 kg/kWh 876.1 MJ/s 234.1 MW 170.2 MW 49.1 MW 24 % 355.2 MW 40.5 %

IGCC WITH COPRODUCTION OF ELECTRICITY AND METHANOL The recovered C02 fraction from the IGCC station described above has to be either disposed of or utilized further. One of the possibilities to use CO2 removed from power plants is the substitution of other feedstocks which could contribute to the reduction of global CO2 emissions. However, to achieve considerable emissions reduction, large quantities of chemical products would have to be required by the market. Annual world-wide CO2 emissions from energetic use of fossil fuels amount to some 20 Gt,

1066 corresponding to a carbon inventory of some 6 Gt. About 20 % result from electric power generation in coal-fired stations representing 1.2 Gt C in the fuel. In contrast, carbon used world-wide for raw materials of the chemical industry such as ethylene, propylene, methanol amounts to only 0.09 Gt C. These figures show that only a small fraction of the CO2 emitted by power plants would be necessary for the production of chemicals, which would not justify demonstration of CO2 reuse technology on technical scale. The only potential worth analyzing more in detail is replacing mineral-oil-based fuels in the transportation sector with methanol, as the major part of the carbon requirement of 1.2 Gt could be provided by CO2 from power plants. For this purpose, CO2 and H2 are converted into the liquid energy carrier methanol which can be stored more easily and which is therefore more suitable for today's transportation sector infrastructure. Bound carbon would then be ultimately released into atmosphere by subsequent combustion. Required H2 has of course to be produced from carbon-free energy sources, for instance by hydropower-driven water electrolysis, to reduce CO2 emissions of the overall system. However, production of methanol using CO2 from power plants can only be justified as long as the problem of storage and transport of hydrogen is not satisfactorily solved on a large scale and for everyone's daily use. Figure 3 shows how a CO2-based methanol synthesis plant, which is not the conventional case, can be integrated into an IGCC station. Hydrogen as a reactant to be imported is assumed to be available at plant limits at 100 % purity and 66 bar. Methanol can be converted further to synthetic gasoline via MTG (methanol to gasoline) process of Mobil Oil.

Figure 3: IGCC plant with CO shift, CO2 removal and utilization for methanol synthesis Salient data of the coproduction system: • • • • •

Coal input 2300 Hydrogen input 780 CO2 (intermediate product) 5500 Methanol product (>99.85 % wt) 3800 Total gross power output 354 Gas turbine 234 Steam turbine 120 • Total net power output 310 • Relative overall energy yield 67

tonnes/d tonnes/d tonnes/d tonnes/d MW MW MW MW %

1067 ECONOMICAL CONSIDERATIONS The specific investment of the IGCC power plant with CO shift and removal of CO2 as a slightly compressed gas was calculated to be 20 % higher than that of the reference IGCC station. Including CO2 liquefaction would cause around 40 % higher specific investment. Electricity generating costs would rise by around 20 % and 50 %, respectively. Total plant investment costs for coproduction of power and methanol/gasoline comprise costs of IGCC station with CO2 removal and of methanol synthesis/MTG plant. Specific costs of coproduced methanol/gasoline strongly depend on hydrogen price. CO2 from IGCC power plants could be considered as for free in case extra costs caused by CO2 removal are allocated to generating costs. In the present case, a simplified cost calculation model has been used which is solely based on investment costs for the additional equipment of the methanol system and hydrogen production costs depending on the different sources. Taking into account that the CO2 stream has been provided by adding a removal plant to a conventional IGCC station, the specific methanol production costs estimated as described above are penalized by the resulting higher generating costs depending on the ratio of electricity and coproduced methanol/gasoline. 0.200 0.175 0.150 0.125 0.100 ~,,,,,,~-

Gasoline Market Price (incl. tax)

~"

b

0.075 0.050 0.025 0.000 0.03

0.04

0.05

0.06

0.07

Hydrogen

0.08

Price

[$/kW

0.09

0.10

0.11

0.12

h]

Figure 4: Methanol/gasoline generation costs vs. hydrogen price In Figure 4, methanol/gasoline production costs are plotted against hydrogen price. General target should be that methanol costs are below market price and gasoline costs are below market price including tax. The diagram shows that even when using very cheap hydrogen sources down to 0.02 US$/kWh, methanol from this coproduction is not competitive. Synthetic gasoline as secondary product is only "profitable" if based on hydrogen sources below 0.05 US$/kWh and not charged with tax. It should be pointed out, however, that all these market prices are subject to permanent changes on the world market. Conditions can become inverted very fast and such an economic analysis should be understood as some kind of snapshot [2]. COMPARATIVE CO2 EMISSIONS Finally, the described coproduction process and separate generation of electric power and methanol, which should be used for transportation in correspondingly modified gasoline engines, have to be compared regarding the total CO2 output. Primary energy sources are then coal and a CO2-free energy source such as hydropower also supplying hydrogen via water electrolysis. In Figure 5, primary energy requirements and accompanying CO2 emissions for different selected cases of interest, which are shortly described below, are compared. It turns out that only power generation in'a conventional IGCC station and parallel use of cars fuelled with hydrogen from a CO2-free source ("Case 2") show a slightly lower CO/output than the IGCC plant under consideration with coproduction of electric power and methanol as substitute for oil-based gasoline ("Base Case").

1068

~ eOi~s IGCX346.7 % H~m R:~er P~nt ~',~

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Otto O~de Engim Gasciin~ 2 ~

t,/, //

M k ~ l h a r d 30o,,,1

Ot to G a ~ i n e

"// ,/z //,

( R ~ n e ~ ) ~0%

Coal to MeUlar'~153% (Cor~. ~

•/ /

0.3~ kg O::~g Gmoine

I~dro P o ~ r 1746IMkN

~ 1751i~lys

17.'51

OO ....

i

x/xz ..v,. xzxz /\/x

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o

~

i

~

k-,,,-,r/A ~., Cutl~t::~0i~en t~E~C~lGCX:;Oesign

-tGCX3 -t-k~F~ ( ~

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~

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"-. -tGCX2 - t - t y ~ t : : ~ l : : ~ -F:~ef~ -~.r,,,~ ( ~

-tG0C -Cw~.t~ (C~

(Case I --- Bla~e CeBe)

Figure 5: Primary energy demand and CO2 emission for combined electrical and automotive power Case 1: Coal-based IGCC station with coproduction of electric power and methanol Case 2: Coal-based IGCC station & hydropower-based hydrogen plant Case 3: Hydropower station & oil-refinery-based gasoline plant Case 4: Coal-based IGCC station & oil-refinery-based gasoline plant Case 5: Hydropower station & coal-based conventional methanol synthesis plant Case 6: Coal-based IGCC station & coal-based conventional methanol synthesis plant

CONCLUSIONS IGCC stations represent the best choice for producing low-CO2 power [3]: either by their outstanding efficiency, which is the second highest after future coal-based solid oxide fuel cell power plants, or by the unique option to separate CO2 from shifted synthesis gas with present technology. The CO2 removed can then, for instance, be dumped in the deep sea or pressed into underground aquifers. Alternatively, CO2 from fossil fired power stations can be used as a feedstock for chemical syntheses reusing the C atom of COl. In case of producing methanol/synthetic gasoline from this C O 2 and H2 from a CO2-free source, significant quantities of CO2 can be utilized. In this way, the overall CO2 emission can be reduced by substituting oilbased fuels for the traffic sector today by using the CO2 captured in the IGCC power station. Depending on the particular hydrogen sources, coproduction of electricity and methanol/gasoline in combination with IGCC stations ends up with production costs around present gasoline market prices including tax. ACKNOWLEDGEMENT These studies were supported in part by the European Commission within the framework of the JOULE II and JOULE III programmes. REFERENCES 1. Pruschek, R. et al. (2000). Improvement of Integrated Gasification Combined Cycles Starting from State of the Art (Puertollano). In: Clean Technologies for Solid Fuels, Vol. III, pp. 3-136 (Contract JOF3-CT95-0004). European Commission EUR 19285/IIIEN, Brussels/B. 2. Pruschek, R. et al. (1997). Coal-fired multicycle power generation systems for minimum noxious gas emission, CO2 control and CO2 disposal. In: Combined Cycle Project- Final Reports, Vol. III (3.1.1), pp. 1-56 (Contract JOU2-CT92-0185). European Commission EUR 17524 EN, Brussels/B. 3. Trevifio, M.(2002). The Puertollano Demonstration Plant and IGCC Prospects in Spain. VGB PowerTech 1/2002, pp. 43-46.

Greenhouse Gas Control Technologies, Volume 1I J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1069

MODELING INFRASTRUCTURE FOR A FOSSIL HYDROGEN ENERGY SYSTEM WITH CO2 SEQUESTRATION Joan M. Ogden Research Scientist, Princeton Environmental Institute, Princeton University Princeton, NJ 08544

ABSTRACT Production of hydrogen (H2) from fossil fuels with capture and sequestration of CO2 offers a route toward near zero emissions in production and use of fuels. Implementing such an energy system on a large scale would require building two new pipeline infrastructures: one for distributing H2 to end-users and one for transmitting CO2 to disposal sites and securely sequestering it. In this paper we develop a simple technical/economic model of a single fossil energy complex linked by pipelines to a geological CO2 sequestration site and a H2 demand center. The goals of the study are to better understand design issues and costs for the total system and to identify the most important factors influencing the sequestration cost of CO2 and the delivered cost of H2. For our base case (large flows of H2 and CO2; nearby CO2 storage reservoirs with good characteristics), the most important factors contributing to the delivered cost of Hz transportation fuel are H2 production, pipeline distribution and refueling stations. The costs of CO2 capture and compression at the H2 plant are significant, but the costs of CO2 pipeline transmission and storage are relatively small. INTRODUCTION

Production of H2 from fossil fuels with capture and sequestration of CO2 would enable continued widespread use of fossil-derived fuels for applications such as transportation, with near-zero full fuel cycle emissions of both air pollutants and greenhouse gases [ 1]. A large-scale fossil H2 system with CO2 sequestration consists of one or more fossil energy complexes plus two pipeline networks--one for distributing H2 to end-users (e.g. H2 vehicles) and one for transmitting CO2 to storage sites and securely sequestering it. The performance and economics of the system depend on: •

• • •

the design of the central fossil energy conversion plant [scale, feedstock (e.g., coal vs. natural gas), process design, electricity co-production, separation technology, pressures and purity of H2 and CO2 products, sulfur removal options including co-sequestration of sulfur compounds and CO2, location (distance from demand centers and sequestration sites)]; the requirements of H2 end-users (scale, geographic density of H2 demand, H2 purity, H2 pressure); the characteristics of the CO2 sequestration site (storage capacity, permeability, reservoir thickness, location); pipeline constraints (e.g., for CO2 pipelines; moisture content must be low; for H2 pipelines, materials must be selected to resist embrittlement; for both, availability of rights of way).

Several detailed technical and economic studies have been carried out for various parts of the system, including CO2 capture from electric power plants [2-4], or H2 plants [5-8], CO2 transmission [9] and storage [10], and H2 infrastructure [11, 12]. However, relatively little work has been done assessing the entire system in an integrated way. This study seeks to understand better the total system design and economics, for the special case of a single large fossil energy complex connected to a geological CO2 sequestration site and a

1070 H2 demand center (such as a city with a large concentration of H2 vehicles) [13]. We estimate the delivered cost of H2 with CO2 sequestration as a function of fossil energy complex design, pipeline parameters, distance to sequestration site, and CO2 injection site reservoir parameters. The model developed here can be extended to fossil H2 energy systems that include multiple fossil energy complexes, H2 demand centers and CO2 sequestration sites. M O D E L OF A FOSSIL H Y D R O G E N ENERGY SYSTEM W I T H COz SEQUESTRATION

Overview of the System We consider energy systems producing H2 and electricity from fossil feedstocks (natural gas or coal), with capture of CO2, compression to 15 MPa for pipeline transmission as a supercritical fluid, and injection into an underground reservoir. H2 is compressed to 6.8 MPa (1000 psi) for on-site storage, pipeline transmission and local distribution to H2 vehicles. We consider H2 plants with an output capacity of 1000 MW of H2, higher heating value basis (25.4 tonnes H2/hr).. At an assumed 80% capacity factor, annual H2 production is 25.2 million GJ (178,000 tonnes)---enough to fuel 1.4 million H2 fuel cell cars having a fuel economy of 2.9 liters gasoline per 100 km (82 miles per gallon) and driven 17,700 km (11,000 miles) per year (the US average). To find levelized costs, we assume a 15% annual capital charge rate and an annual non-fuel O&M charge of 4% of the installed capital cost. Feedstock costs are USDOE projections for 2020 costs to electric utilities: $3.75/GJ for natural gas and $0.95/GJ for coal [ 14]. Costs are in constant 2001 US dollars. Fossil Energy Complexes Producing Hydrogen and Electricity The assumed performance and cost characteristics of 1000 MW H2 plants are summarized in Table 1. The coal-based and natural-gas-based energy complexes are taken from the "Conventional Technology" case in [8] and from [5] respectively. H2 compression to 6.0 MPa and CO2 compression to 15 MPa are included in all H2 plant designs. From Table 1, we see that coal to H2 plants have larger capital costs but lower feedstock costs, so that the levelized H2 production cost is somewhat lower than for natural gas. The coal to H2 plant produces about twice as much CO2 as the natural gas to H2 plant. TABLE 1 1000 MW FOSSIL HE PRODUCTION PLANTS W/CO2 CAPTURE AND COMPRESSION H2 from Natural Gas [4] Hz from Coal [81 Electricity net production Mwe 0 31 First law efficiency, HHV =(H2 + elecout)/Feedstocki, 78% 68.7% CO/emitted (tonne/h) at full capacity 36 34 CO2 captured (tonne/h) at full capacit), 204 406 429 731 Installed Capital Cost of H2 Plant (million $) Levelized Cost of Hz Production ($/GJ HI-IV) Plant capital (=15% of capital cost) 2.56 4.35 Non-fuel O&M 0.39 1.00 -0.26 Byproduct electricity credit 4.71 1.41 Feedstock 7.66 Total 6.50 These results can be extended to smaller complexes, using appropriate scaling factors [ 13]. At 250 MW the H2 production cost is about $2/GJ higher than at 1000 MW [13].

Hydrogen Pipeline Distribution Costs for H2 distribution and refueling systems are shown in Table 2. We assume that coal-derived H2 is transmitted 100 km to the "city gate", where it is recompressed and enters a local network bringing H2 to refueling stations. Natural gas-derived H2 is produced at the city gate. Based on the flow equations in [15,16], the optimal 100 km H2 transmission pipeline diameter is 0.29 m, and the associated cost is $0.35/GJ, for a 1000 MW plant and pipeline inlet and outlet pressures of 6.8 MPa and 1.4 MPa, respectively. (For long distance pipelines, capital costs are taken from [15] and recent industry estimates [ 17].) For an alternative H2 energy flow rate Q and pipeline length L, the cost can be estimated as 05 1.25 ($0.35/GJ) x (O/1000 M W ) - x (L/100 k m ) .

1071 For local H2 distribution within a city via small (0.1-0.2 m diameter) high pressure pipelines, we assume the installed cost of the H2 pipelines is $622/m ($1,000,000 per mile), independent of pipeline diameter [ 11 ]. We assume that H2 is distributed radially outward from a central hub through "spokes," along which the pressure drops from 6.8 MPa to no less than 1.4 MPa at the outermost refueling stations. For our base case, each of 10 spokes has 25 refueling stations, each dispensing 2.4 tonnes (1 million standard cubic feet) of H2 per day. Assuming an 80% capacity, factor, this is matched to 5600 cars per station. For a geographically dense demand of 750 H2 cars/km~(about half the average density of cars in the Los Angeles area), each "spoke" is 28 km long. The levelized cost for pipeline capital for this local H2 distribution system is $1.29/GJ. An important component of the distribution system is above-ground H2 storage at the central H2 plant, with capacity equivalent to one half day's production. This storage is needed to assure supply in case of outages and to account for time variations in H2 demand. We assume a capital cost of $5000 per GJ of H2 storage capacity for storage cylinders, or $216 million, based on current industrial bulk compressed H2 gas container technology. The levelized cost contribution of central H2 storage is significant, $1.63/GJ(H2). Lower cost bulk storage is clearly desirable, where possible; underground storage in aquifers or salt caverns is likely to be less costly [11]. (For comparison, at high levels of mass production (300,000/y) the capital cost of onboard high pressure H2 cylinders for cars is projected to be about $1500 per GJ of storage capacity [12].) At lower H2 demand density, the cost contribution of local pipeline distribution increases as (1/vehicle density) °5, while the central storage cost is insensitive to scale. Below a certain demand density, non-pipeline H2 distribution or onsite H2 production will provide a lower delivered cost. TABLE 2 H2 DELIVERY SYSTEM FOR 1000 MW H2 PLANT SERVING 1.4 MILLION H2 CARS ] H2 from natural gas

[ H2 from coal

Hz Distribution and Refueling System Capital Cost (million $)

Central Ha Plant Buffer Storage(I/2 day's output of H2 Plant) H2 Pipeline from HE Plant to City Gate 100 km(coal only) Citygate H2 Booster compressor (24 MWe) H2 Local Distribution Pipelines (750 cars/km~) Sub-total H2 Distribution (excluding refueling stations) H2 Refueling Stations (252 stations) Total

216

216 47

171 387 375 762

171 452 375 827

Levelized Cost of H2 Distribution and Refueling ($/GJ Hz)

Central H2 Plant Buffer Storage H2 Pipeline from H2 Plant to City Gate 100 km (coal only) Citygate H2 Booster compressor (coal only) H2 Local Distribution Pipelines Sub-total 1-12Distribution (excuding.refueling station). H2 Refueling Station Total

1.63

1.63

0.35 0.55 1.29 2.92 6.06 8.98

1.29 3.27 6.06 9.88

Hydrogen Refueling Stations H2 is dispensed to vehicles at refueling stations as a high-pressure gas (at 34 MPa) for storage in onboard cylinders. It is estimated that a refueling station dispensing 2.4 tonnes (1 million standard cubic feet) of H2 per day costs $1.5 million, adding $6.1/GJ to the delivered cost of H2 (see Table 2) [ 11 ] About 80% of the capital cost and 50% of the levelized cost is due to H2 compression at the station and storage cylinders. The remainder is due to capital for dispensers and controls, and labor costs. The cost of on-board H2 storage is not included. Development of a new H2 storage technology that requires less capital and energy input than compressed gas could reduce refueling station costs. C02 Pipeline To model supercritical CO2 pipelines, we use pipeline flow equations developed in [ 16] and [18]. Published estimates of capital costs for CO2 pipelines vary over more than a factor of two above and below the midrange value used here [6, 9, 10, 13, 20]. Local terrain, construction costs and rights of way are all important variables in determining the actual installed pipeline cost. Using a cost function fit to published pipeline data, and inlet and outlet pressure of 15 MPa and 10 MPa, respectively, we find a pipeline capital cost per unit length (S/m), in terms of the flow rate Q and the pipeline length L [13]:

Cost (Q,L) = $700/m x (Q/Qo) 0"48x (L/Lo) 0"24

[i]

1072 Here Qo = 16,000 tonnes/day and Lo = 100 km. The levelized cost of CO2 pipeline transmission is $3.45/t CO2 for the coal H2 plant and $5.26/tCO2 for the natural gas H2 plant. It is assumed that booster compressors are not needed for this 100 km pipeline. For transmission of more than 100 km, boosters might be needed. C02 Sequestration The injection rate of CO2 into an underground reservoir depends on the permeability and thickness of the reservoir, the injection pressure, the reservoir pressure, the well depth, and the viscosity of CO2 at the injection pressure. A practical upper limit on the injection rate per well is taken to be 2500 tonnes per day, limited by pressure drop due to friction in the well at higher flow rates, assuming practical well diameters [2]. Using a standard equation for flow into an injection well [2], this upper limit implies that for a layer thickness above 50 m and permeabilities above 40 milliDarcy, the flow rate is limited not by the reservoir characteristics, but by the pipe friction flow constraints. For the 1000 MW natural gas (coal) to H2 plant, producing about 5,000 (10,000) tonnes CO2 per day, 2 (4) wells are needed. The installed capital cost of each well is [2]: Capital (S/well) = $1.56 million x well depth (km) + $1.25 million. We assume a well depth of 2 km. CO2 is distributed by surface piping at the injection site from well to well. We require each reservoir to store 20 years of CO2 production from the H2 plant. For our base case (reservoir thickness of 50 m), the length of surface piping required at the injection site is found to be 12 (37) km for the natural gas (coal) based H2 plant. This implies a cost of $3.2 (9.2) million, based on a piping cost from Equation TABLE 3 CO2 PIPELINE TRANSMISSION AND STORAGE SYSTEM ] H2 from natural I~as I H2 from coal CO2 Disposal System (100 km pipeline~ 2 km well depth~ injection rate = 2500 t CO~/day/weil) 0.34 CO2 100 km Pipeline Diameter (m) 0.25 Number of CO2 Injection Wells 2 37 Iniection Site Pipin~ length (km) 12.2 System Capital Cost (million $) 55.7 CO2 100 km Pipeline 40.5 17.5 8.8 CO2 Injection Wells 3.2 CO2 Injection Site Piping 9.2 Total C02 Pipeline Transmission and Storage System 82.4 52.5 Levelized Cost of CO2 Disposal ($/tCOz) 5.26 3.45 CO2 100 km Pipeline 1.17 1.16 CO2 Injection Wells 0.44 0.61 CO2 Injection Site Piping Total C02 Pipeline Transmission and Storage System 6. 87 5.23 Total CO2 Pipeline Transmission and Storage System ($/GJ H2) 0.39 0.59 [1], but assuming that the minimum cost is $155,000/km ($250,000/mile) [11]. As long as the aquifer characteristics allow such a relatively high injection rate, the cost of injection wells and associated piping is less than $2/tonne CO2 [$0.10(0.26)/GJ(H2) for H2 from natural gas(coal).] The total levelized cost of CO2 pipeline transmission and storage is shown in Table 3. Per tonne of CO2, the cost of CO2 disposal is higher for natural gas, but because the coal plant produces about twice as much CO2 as the natural gas H2 plant, the contribution to the levelized cost of H2 ($/GJ) is higher for coal. However, the sum of the costs for CO2 capture ($1.33/GJ H2 for natural gas [19] and $0.95/GJ H2 for coal [8]) and disposal ($0.39/GJ H2 for natural gas and $0.59/GJ H2 for coal) is about same for natural gas and coal.

1073 S U M M A R Y OF R E S U L T S FOR SYSTEM CAPITAL COST AND D E L I V E R E D H Y D R O G E N

COST In Figure 1, we summarize our results for 1000 MW H2 plants based on natural gas and coal, with CO2 capture.

System Capital Cost For the "fully developed" H2 economy described here, serving a geographically concentrated market of 1.4 million HE cars, the total system capital cost varies from about $1200-1600 million or $900-1200/car. H2 pipeline distribution systems and refueling stations, together, contribute about 1/2 to 2/3 of the total capital cost. These costs are dominated by H2 compression and storage cylinders. This highlights the importance of developing better H2 storage methods that require lower energy inputs and costs than high pressure compressed gas. H2 production systems are also major contributors to the system capital cost, with coal plants about 1.7 times as capital intensive as natural gas plants. For our assumptions (100 km pipeline, and desirable reservoir characteristics), CO2 pipelines and wells contribute only about 5% to the system capital cost. The incremental total system capital cost of sequestration for the 1 GW H2 system considered here, relative to the same system without sequestration, is about 20% (3%) for natural gas (coal) H2 energy systems [5, 8, 13].

Delivered Cost of Hydrogen For our base case, the delivered cost of H2 is about $17.0 (16.9)/GJ for H2 from natural gas (coal) (Figure 1). HE production, distribution and refueling contribute 45% (38%), 17% (22)% and 35% (36)%, respectively. CO2 capture compression, pipeline transmission and storage add about $1.7 (1.5)/GJ (-~10%) to the delivered cost of H2 transportation fuel compared to cases where CO2 is vented. Of this, only about $0.39(0.59)/GJ or 2% (3%) is due to the CO2 pipeline and storage. Delivered H2 costs are sensitive to scale economies in both H2 production and pipeline transmission. Geographic density of demand is key to the economic viability of widespread gaseous H2 distribution. In the early stages, when demand is relatively low and geographically diffuse, trucked-in H2 or distributed H2 production (e.g., via small scale natural gas reforming at refueling sites) would be preferred from a cost perspective [ 11].

Capital Cost(million $)

Delivered H2 Cost $1GJ ding

1800 1600 1400 1200 1000 8O0 600 4O0 2O0

Distrib

• H2 Refuel Sta O&M • H2 Refueling Sta Capital • H2 Local Pipeline

ne (100 km)

• H2 Pipeline (100 km) • H2 Storage at Plant

ge at H2 Plant Is+lnj Piping

• CO2 Injection Piping • CO2 Wells ICO2 Pipeline (100 km)

.=line (100 km)

[] H2 Plant O&M • Feedstock • H2 Plant Capital

H2 from NG

H2 from Coal

Figure 1: The system capital cost and the delivered cost of H2 are shown for H2 produced from natural gas and coal with CO2 capture, transmission and storage, and H2 pipeline distribution and refueling. The H2 plant capacity is 1000 MW, which is large enough to support 1.4 million H2 fuel cell cars. CONCLUSIONS Using a technical/economic model of large-scale fossil H2 energy systems with CO2 sequestration, we have identified the major factors contributing to the delivered cost of H2, and their most important sensitivities. For our base case assumptions (large CO2 and H2 flows; a relatively nearby reservoir for CO2 sequestration with good injection characteristics; a large, geographically dense H2 demand), H2 production, distribution and refueling were found to be the major costs contributing to the delivered H2 cost. CO2 capture and sequestration added only -~10%. Better methods of H2 storage would reduce both refueling station and

1074 distribution system costs, as well as costs on-board vehicles. The models developed here will be used in a future regionally specific case study of H2 infrastructure development with CO2 sequestration, involving multiple sources and sinks for CO2 and multiple H2 demand sites. REFERENCES

Williams, R.H. (1998). "Fuel Decarbonization for Fuel Cell Applications and Sequestration of the Separated CO2," in Eco-restructuring: Implications for Sustainable Development, Ayres (ed.), United Nations Univ. Press, 180-222. 2. Hendriks, C.A. (1994). "Carbon Dioxide Removal from Coal-Fired Power Plants", Ph.D. thesis, Department of Science, Technology, and Society, Utrecht University, Utrecht, The Netherlands. 3. Foster Wheeler (1998), "Precombustion Decarbonization," Report Number PH2/19, prepared for the IEA Greenhouse Gas R&D Programme. 4. Simbeck, D., 1(999), "A Portfolio Selection Approach for Power Plant CO2 Capture, Separation, and R&D Options", Proceedings of the Fourth International conference on Carbon Dioxide Removal, Pergamon Press, pp. 119-124. 5. Foster Wheeler (1996)" Decarbonization of Fossil Fuels, Report No. PH2/2, prepared for the Executive Committee of the IEA Greenhouse Gas R&D Programme of the International Energy Agency, March. 6. Doctor, R. et al. (1999). "H2 Production and CO2 Recovery, Transport and Use from a KRW Oxygen Blown Gasification Combined Cycle System," Argonne National Laboratory Report. 7. Spath, P.L. and W.A. Amos (1999), "Technoeconomic Analysis of Hydrogen Production from Low BTU Western Coal with CO2 Sequestration and Coalbed Methane Recovery Including Delivered H2 Costs," Milestone Report to the US DOE H2 Program.. 8. Kreutz, T., R. Williams, R. Socolow, P. Chiesa and G. Lozza (2002), "Analysis of Hydrogen and Electricity Production from Fossil Fuels with CO2 Capture," Proceedings of the 6th International Conference on Greenhouse gas Control technologies, 30 Sept-4 October 2002, Kyoto, Japan. 9. Skovholt, O. (1993), "CO2 Transportation System," Energy Conservation and Management, 34(91I):1095-1103. 10. Holloway, S. (1996) An overview of the Joule II Project. Energy Conversion and Management 37(1-2): 1149-1154. 11. Ogden, J. (1999), "Prospects for Building a Hydrogen Energy Infrastructure," Annual Review of Energy and the Environment, 24, 227-279. 12. Thomas, C.E., B.D.James, F.D. Lomax, and I.F. Kuhn, (1998). Draft Final Report, Integrated Analysis of Hydrogen Passenger Vehicle Transportation Pathways, report to the National Renewable Energy Laboratory, U.S. Department of Energy, Golden, CO, Under Subcontract No. AXE-6-16685-01, March. 13. Ogden, J. and H.Y.Benson (2002). "Modeling a Fossil Hydrogen Energy System with CO2 Disposal," Princeton University, Carbon Mitigation Initiative, Technical report, forthcoming. 14. U.S. Energy Information Administration (2001). "Energy Outlook 2002, with Projections Through 2020," DOE/EIA0383(2002), U.S. Department of Energy, Washington, DC. 15. Christodoulou, D. (1984)."The Technology and Economics of the Transmission of Gaseous Fuels," Master's Thesis, Department of Mechanical and Aerospace Engineering, Princeton University. 16. Mohitpour, M., H. Golshan, and A, Murray (2000), Pipeline Design and Construction, A Practical Approach, American Society of Mechanical Engineers, New York. 17. Jandrain, C.(2001, 2002), BP Pipelines, private communications. 18. Farris, C.B. (1983). "Unusual Design Factors for Supercritical CO2 Pipelines," Energy Progress, 3, 150158. 19. Williams, R.H. (2002) "Toward Zero Emissions for Transportation Using Fossil Fuels," in VII Biennial Conference on Transportation, Energy and Environmental Policy: Managing Transitions in the Transportation Sector." How Fast and How Far, K.S. Kurani and D. Sperling, ed.s, Transportation Research Board, Washington, DC, forthcoming. 20. Fisher, L., T. Sloan, P. Mortensen (2002). "Costs for Capture and Sequestration of Carbon Dioxide in Western Canadian Geologic Media," Canadian Energy Research Institute, Study No. ISBN 1-896091-784, June. 1.

ECONOMICS

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1077

A CO2-1NFRASTRUCTURE FOR EOR IN THE NORTH SEA (CENS)" MACROECONOMIC IMPLICATIONS FOR HOST COUNTRIES P. Markussen l, j. M. Austell 2 and C-W. Hustad 3 z Elsam AS, DK-7000 Fredericia, Denmark, ([email protected]). 2 INCO2 ApS, Box 39, DK-9370 Hals, Denmark, ([email protected]). 3 CO2-Norway AS, Box 592, N-3605 Kongsberg, Norway, ([email protected]).

ABSTRACT

The CO2" for EOR in the North Sea (CENS) Project offers the host nations a unique opportunity for securing future energy supplies while developing sustainable solutions in ......................................................................................................................................................................... response to the challenge of climate change and compliance with their Kyoto commitments. The Project comprises a CO2-pipeline infrastructure in the North Sea capable of transporting more than 30 million tonnes CO2 per year (mtCO2/yr). The CO2 will initially be captured from on-shore coal-fired power plants in the UK and Denmark, and used commercially for Enhanced Oil Recovery (EOR) in the maturing oil reservoirs in the North Sea. The scope of the CENS Project entails not only collaboration between the CO2-producers, transporters and users, but also the host countries. Only when these are active participants does the project reveal a 'winwin-win' situation for all stakeholders, including host governments.

............ Figure 1: Sketch of the CENS concept super-posed on a relief map of the North The CENS Economic Models (CEM) shows that during a 25-year q~ h~i, "economic" lifetime, the project could produce 2,1 billion barrels of incremental oil obtained while sequestering 680 mt CO2 in recognised secure depositories. Assuming price of oil at $20 /bbl then the net cost for CO2capture and sequestration is less than $1,50 per tonne--this represents one of the cheapest options available to the host nations for CO2-emission reductions. We do not for the time being attribute any value to the CO2-credits that may also be generated within the project.

In this paper we briefly elaborate on some of the macroeconomic benefits that the project can produce, including increased tax income, energy security, improved oil recovery, technology development, reduced CO2-emissions, capital investment and jobs. We also indirectly infer some longer-term benefits of a CO2-infrastructure whereby Northern Europe may be in a position to decarbonise existing CO2-emissions during the next half century using ageing oil and gas reservoirs. Furthermore we perceive an accelerated commercial route towards a "hydrogen economy"minitially based on decarbonisation of fossil fuels [1] that can be supplemented by new-renewable hydrogen production, as these become commercially developed.

* We consistently use C02 as opposed to C02 for denoting carbon dioxide.

1078 INTRODUCTION The CENS Project is essentially a 25-year project for enhanced oil recovery (EOR). It is made possible by the maturing state of the oil reservoirs on the UK and Norwegian sectors of the North Sea Continental Shelf (NSCS). In Fig. 2 comparison is made with the similar situation that occurred in the US in the early 1980's. This stimulated the introduction of CO2 for EOR, particularly in West Texas where there now exists a 1500 km CO2pipeline infrastructure transporting 22 IWl~l~na~ mtCO2/yr--the majority of which is I~ ~ obtained from naturally occurring geologic 4,0 formations. The Houston-based Kinder Morgan C02 Company (KMCO2) is the major operator of the Texas-pipeline infrastructure. In addition KMCO2 owns and operates the SACROC oilfield, West Texas, which is currently the world's largest CO2-flood.

3,0 2,0

0,0 o o o o o o o ,.,. _ ~ ~D t... O0 ¢lr) 0 s~. The potential use of CO2 for EOR in the G) q~) 0') G) 0 0 0 North Sea region is also made possible by 'e~e~ ~-' ~I ~ ¢~1 O Z a growing concern regarding CO2emissions from coal-fired power plants in Figure 2: Comparison between US and North Sea oil production (1%0 Denmark and the UK. These plants have a 2020). The NSCS is currently moving into decline in a similar manner that occurred in the US in the early 1980's. relative close proximity to the NSCS and represent the cheapest 'end-of-pipe' CO2 available to the oil field operators in a sufficient volume to warrant fullscale use of CO2 for tertiary oil recovery. It is also recognised that there are many additional sources around the North Sea rim that can in the future supplement this initial 'base volume' of CO2-supply [2].

Furthermore the commercial use of CO2 captured from coal combustion is appealing due to the recognised dominance that coal has within energy production. Inevitably, on the global arena, this will probably remain the case despite the move towards lower carbon content fuels (i.e. natural gas) in many of the industrialised economies. It is the detrimental impact of coal on the environment that is of major concern [3]. The potential for removing CO2-emissions commercially from existing coal plants using post-combustion decarbonisation should possibly strengthen the perceived global role for coal in a 'carbon constrained' global economy during the next half-century. The longer-term implications of CENS suggests that the project may also be seen as an opportunity to straddle the gap between an existing high carbon fossil-based economy through to a sustainable renewable energy economy via decarbonisation, hydrogen-rich syngas and carbon sequestration. Within this perspective CENS could be a fundamental building block for commercially developing the necessary technology for economic and sustainable energy in the future.

O V E R V I E W OF THE CENS E C O N O M I C M O D E L The CENS Project primarily comprises four projects that cover: (i) power plant CO2-capture, (ii) CO2transportation, (iii) CO2-injection for EOR, and (iv) CO2-stripping and recycling. Within the CENS Economic Model (CEM) each one of these are subsequently broken into sub-projects having specific capital investments, operational costs, revenue streams, capital charges, etc. The CEM contains nearly 50 inter-linked data sheets covering all the economic components of the project, together with summary sheets for specific sectors and host nations. Many of these sheets also incorporate macroeconomic aspects such as jobs created, technology development, taxation revenue, and other societal benefits that are not directly relevant to the project microeconomics. We can also make comparison with the 'No-CENS' case based on forecast production profiles and decommissioning costs for specific fields if the project does not occur.

1079

The essence of CENS is as a multi-discipline project with stakeholders from several separate sectors--all must see a satisfactory internal rate of return in order to individually move forward and invest capital. Our fiscal and macroeconomic modelling shows that a 'win.... ......: t:~: ,I win-win' situation occurs for all stakeholders i!~,i~!U~~'...... ~ rlmli : : , ,' ,.............~1 only when the host governments also become I~i~:i~::~i::!!~:' ~ !...... ~ , . ~:~:,:~:~-~ B t ~ t , - ~ ! l : ....~ :o~:ili~i~'~ active stakeholders and project facilitators. /1 : :~i,::.... ~ Nt~w*~'//~~~~l'~+~;~ An overview of the project concept is shown in Fig.3. The designated fields are chosen as suitable candidates for CO2-flooding based on their existing production profiles and original oil in place (OOIP). They should be viewed as representative of a general portfolio of potential fields for the period 2006 - 2012 J'. The main components of the project, as currently envisaged, comprises an onshore pipeline infrastructure in Denmark (sketched) and UK (not shown), together with two main (24-inch diameter) feeder lines joining a southern hub near Fulmar and Ekofisk. The main 'backbone' is a 30-inch diameter pipe transporting the CO2 north to the fields in the Tampen area off the West Coast of Norway. There

is also some scope

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,~,Figure 3: Overview of possible CO2-pipeline infrastructure together with a portfolio of mature oil reservoirs that are representative candidatesfor CO2-flooding. Note that Sleipner and Brae are additional sources of CO2 having a comparatively high percentage as associatedgas(equivalenttol-2mtCO2/yrrespectively).

industrial and power complexes in Scotland with an additional feed line from St. Fergus via possibly fields like Forties or Claymore. These are representative of reservoirs in the more mature part of the North Sea requiring CO2 at the earliest possible opportunity starting 2006 - 8. The feed line from the west of Norway to Tampen is primarily motivated by Norway's unique position as a major oil and natural gas (NG) exporter 1:. By 2005 it is anticipated that total production of NG from the Norwegian sector of the North Sea will be around 140 bcm. However, the annual domestic consumption is presently less than 4 bcm. For this reason there is a strong desire to use gas onshore, combined with a need for decarbonisation in order to comply with Norway's Kyoto commitment. It is already well recognised that Norway is currently a major promoter for developing "zero-emission" Capturing 90% of the C02 emitted from Elsam's coal4ired power power plant technology[4]. plants is commercially competitive because:

C02-Capture

• Ultra clean flue,gas with FGD and SCR are already Installed.

The Danish company Elsam A/S own and operate five major coal-fired power plants in Denmark with total installed capacity of 2,5 GW producing a maximum of 15 mtCO2/yr. During the past year they have conducted extensive investigations with major technology suppliers for installation of standalone post-combustion CO2-capture in conjunction with these power plants. The on-going work has provided detailed cost breakdown and identified

• The flue-gas concentration is 12 - 14% CO2, which is three limes the concentration for Natural Gas power plants. , Steam at 290 bar / 580 °C minimises efficiency drop in conjunction with integration of amine capture technology. • Integration with district heating also helps reduce loss in overall plant efficiency. • Close proximity to NoRh Sea CO2-1nfrastructure. • Potential production of between 10,15 million tonnes CO2 per year from 5 plants.

t More recent work has also revealed clusters of smaller 'non-commercial' fields that also may be favourably disposed to CO2flooding. The optimal economics of these fields is currently being investigated. In 2001 Norway was responsible for exporting 4.2% of global oil consumed. At the same time it is also developing natural gas reserves equivalent to one-quarter of total European reserves. Annual export of natural gas to the European market was in 2001 around 57 billion cubic metres (bcm)--about 12% of total European gas consumption--but this is expected to reach 80 bcm by 2005. An additional 50 bcm of hydrocarbon (HC) gas is currently used for enhanced oil recovery (EOR), and it is uncertain regarding how much of this gas will be economically retrievable towards the end of the oil fields operational life.

1080 improvements for better energy efficiency and cost reductions compared with earlier published studies. The CAPEX for a standalone capture plant varies from US$140 - 195 million with size range 400 - 800 MW. Power plant load factor depends on the local co-generation configuration but will typically vary from 70 - 90%. The CEM also includes 18 potential coal-fired power units in the UK, but currently only four of these (yielding 16 mtCO2/yr) are part of the present economic analysis. The UK plants have been chosen because of their location near the coast, and that they have a similar cost potential as their Danish counterparts. However, overall the exact cost of capture will depend upon final project configuration, volume of CO2 demand, and the rate at which the CO2-offtakers come on-line in the period 2 0 0 6 - 12.

C02- Transportation KMCO2 have with INTEC Engineering B V conducted extensive studies regarding pipeline routing, size and power requirements. The scenario shown in Fig.3 comprises 1500 km of CO2-pipelines offshore together with 900 km onshore in Denmark and the UK. The total transportation investment cost is estimated to be $1,69 billion. However again, the detailed extent of the pipeline economics can only be determined once the suppliers and offtakers have confirmed volumes to be transported, and dates for delivery of initial gas. Despite this uncertainty the CEM does provide a capability to analyse different scenarios for a North Sea infrastructure, thereby yielding an envelope of values for capture and transportation costs. To date our scenario analysis suggests that the 'end-of-pipe' cost for delivered CO2 will be in the range of $32 - $35 per tonne. Elsam and KMCO2 are currently comfortable with confirming that $35/tCO2 is sufficient for both of them to make a commercial investment decision for first delivery of CO2 to the oil field operators in 2006.

C02-Injection for Enhanced Oil Recovery CO2 for EOR will require major investments to the oil platforms and oil reservoirs. However there already exists considerable onshore experience from the Permian Basin, West Texas regarding reservoir response and corrosion mitigation. Furthermore the handling and injection of CO2 offshore is well established practice (see Figs. 4 and 5). Offshore CAPEX will be platform and field dependent, thus difficult to predict with any certainty before focusing on specific installations together with the operator. In this area the CEM is conservative in its assumptions. We model a total offshore investment of nearly $5 billion spread over 12 fields. We believe this is a substantial

k

Figure 4: The Sleipner-T (CO2 amine-treatment) and Sleipner-A(production)platforms, where 1 mtCO2/yr are currently treated and injected by Statoil as part of a pilot studyon saline aquifer storage in the North Sea.

investment covering what will be needed for topside modifications and 'down hole' corrosion protection before a platform may initiate a CO2-flood. We also note that the project economics is reasonably robust to allow for an offshore investment of $6 billion if necessary. Furthermore we assume that only 6% of the original oil in place (OOIP) will be recovered. Experience has shown that the actual value will often vary in the range from 6 - 15%. Although the true value of the CO2 in the reservoir can only be estimated with detailed compositional modeling, experience shows that it is optimized through careful monitoring of reservoir response during the CO2-fiood process. We assume that 6,000 cubic feet of CO2 is necessary to produce one barrel, this being equivalent to 3,1 bbl/tCO2-injected. This is also recognized as being a conservative estimate. Decommissioning costs ($150 million per platform) are deferred to allow for extended field operations. In both the UK and Norwegian sectors much of these costs are to be carried by the respective governments. The model also includes possibility for variation in the taxation regimes by each host government, including royalty, petroleum revenue tax (PRT) and corporation tax. Furthermore the rules governing depreciation of invested capital can be modified in the model.

1081

C02-Stripping and Recycling A main feature of existing onshore CO2-floods is that following initial CO2 injection there is typically a 9 - 18 month response time before increased oil production. For offshore fields, with sparser injector and producer well spacing, this response may be 18 - 36 months. The model assumes two years (and tests sensitivity of field IRR using one and three years). Subsequently as the EOR phase evolves there is a need for stripping CO2 from the produced crude and re-injection. As illustrated in Fig. 5 such technology is already adapted for offshore applications. The incremental cost of handling CO2enriched crude, stripping, drying and re-injection into the reservoir is estimated in the model as $1,5/bbl. PROJECT E C O N O M I C S Figure 5: A CO2-membrane stripping unit (highThe CENS Project requires integration of sub-projects within lighted) attached to an offshore platform operated three main industry sectors: (i) power plant CO2-capture, (ii) by Unocal in the Gulf of Thailand. The unit shown CO2-transportation, and (iii) CO2-injection for EOR (with here is handling 1,8 mtCO2/yr. CO2-recycling). For comparison purposes we average the IRR and NPV of each sub-projects so as to provide an initial indication regarding how the three sectors will perform. We weight the averaging with respect to the capital investment of each sub-project. All net present values (NPV's) used are assuming an 18% discount rate for oil field operators, 15% for the pipeline operators, 12% for power plant owners, and 7% for the governments. These differences respectuto a certain extent--the real expectation for the return on capital invested in the different sectors.

In the CEM we can also look at modifications in the tax structures while comparing pre- and post-tax project economics, as well as IRR between a full equity and a loan-financed project (assuming 6% interest rate). We maintain that the price of coal is $1,50 /GJ, the cost of electricity is $25 /MWh, and oil is at $20 /bbl. Comparisons presented in this paper are assuming a 40% debt-financed project. Using the above we find that an 'end-of-pipe' delivery sale price for CO2 of $35 per tonne will satisfy investment hurdle-rates that are typical in sectors (i) and (ii). However the economic model also shows that the offshore EOR projects will need an oil price of $29,37/bbl to satisfy typical investment requirements in sector (iii). Alternatively with oil at $20/bbl then the necessary CO2 sale price to the oil field operators would be $12,07 /tCO2. This is a level that is not sustainable for projects in sector (i) and (ii). We have currently attributed no value to the potential CO2-credits that may eventually be generated and distributed among the project stakeholders. However it is also evident that the shortfall in price of $22,93 is not a realistic credit value that the emerging emission-trading market would currently support, and therefore does not provide any basis for making an investment decision for a project in the 2 0 0 6 - 2012 time frame.

MAKING CENS FOR THE HOST NATIONS Ultimately it is the host nations that perceive a net benefit through participating in the CENS project. The economic model indicates that with the current tax structure these governments will obtain an incremental $5,79 billion in fiscal revenue by way of direct petroleum-, corporation- and income taxation. At the same time a CO2support price of $22,93/tCO2 is equivalent to an expenditure of $6,77 billion. The net deficit of $0,98 billion is the (discounted) cost these governments need to pay in order to remove 680 mtCO2-emissions from the atmosphere at a price equivalent to $1,44/tCO2 over the 25-year duration of the project. The CEM also shows that if the oil price rises above $21,18/bbl then the host nations become net beneficiaries of the project. (If the offshore capital investment increases from $5 to $6 billion then the price of oil would need to rise above $22,21/bbl before host nations became net beneficiaries.)

1082 Altematively if we maintain oil at $20/bbl, but assume that a credit trading value of $5/tCO2 is available to the project participants, (with this being distributed internally one-third to each sector). Then the credit value will reduce the required CO2-sales price from $35 to $33,24/tCO2, and ensure a net government surplus of $0,71 billion. This is equivalent to a positive income of $1,04/tCO2-captured. Increasing the CO2-credit to $10/tCO2 leads to a government surplus of $2,41 billion and a positive income of $3,53/tCO2-captured. The preliminary calculations using the economic model also indicates that there is little incentive for host governments to reduce their Special Tax (in Norway at 50%) and PRT (in UK at 50%), as this decreases their petroleum income and net benefit. However on the Norwegian side we observe that modifying the linear depreciation for capital investment from six to three years does have a marked favourable influence on IRR of the Norwegian EOR projects.

CONCLUSIONS The CENS Economic Model (CEM) is still at an early stage of development, and we have in this paper simply wanted to indicate a few examples of approximate costs, benefits and sensitivities. To date we have made every effort to remain conservative in our assumptions by including the reality of our different business environments. The most crucial part of the model that still needs to be better elaborated upon concerns the offshore capital investment, and the final 'value' of the CO2 in the reservoir. This work is in progress with the oil field operators. Furthermore there are numerous 'what-if' scenarios that can be considered using the CEM. We believe that the model may also become a useful tool to help host governments assess possible strategies for CO2-emission reductions and identifying incentives to further the use of CO2 for EOR in the North Sea.

ACKNOWLEDGMENTS The CENS Project has evolved in close dialogue between the project developers (Elsam / KMCO2), technology providers, oil companies, and power plant operators. Furthermore there has been considerable dialogue with governmental departments in the UK, Norway and Denmark. The Project would therefore like to thank all those that have provided valuable information and support, including specifically the Norwegian Petroleum Directorate (NPD), Danish Energy Agency (ENS), UK-TradePartners, Department of Trade and Industry (DTI), and many individuals who have helped promote the project in a constructive manner--thank you! The authors thank the management of Elsam A/S and Kinder Morgan C02 Company for their permission to publish the material contained in this paper, and acknowledge our colleagues who have contributed within the CENS Project Management Team. These are: Marius Noer, Benny Hansen Mai and Claus Straegaard Graversen, Elsam; Charles Fox, Russel Martin and David L. Coleman, KMC02; Hugh Sharman, INC02.

REFERENCES Blok, K., Williams, R., Katofsky, R. and Hendriks, C. (1997). "Hydrogen Production from Natural Gas, Sequestration of Recovered CO2 in Depleted Gas Wells and Enhanced Natural Gas Recovery", International Journal of Hydrogen Energy, Vol. 22, No.2/3, pp.161-168. Holt, T. and Lindeberg, E., (1993). "CO2 from Industrial Sources as Injection Gas in Oil Reservoirs", Energy Conversion Management, Vol. 34, No.9-11, pp.1189-1196. The Economist Magazine, (2002), p.11 & p.81-82, 6 - 12 July. Hustad, C-W., (2001). "Review over Recent Norwegian Studies Regarding Cost of Low CO2-Emission Power Plant Technology", in Proc. of Fifth Intl. Conference on GHG-Control Technologies, pp.12951300. Eds. Williams, D., et al., ISBN 064306672, CSIRO Publishing, Australia.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1083

ECONOMIC MODELING OF THE GLOBAL ADOPTION OF CARBON CAPTURE AND SEQUESTRATION TECHNOLOGIES J. R. McFarland 1, H. J. Herzog 2, and J. Reilly3 1Technology and Policy Program, M.I.T., Cambridge, MA. 02139, USA aLaboratory for Energy and the Environment, M.I.T., Cambridge, MA. 02139, USA 3joint Program on the Science and Policy of Global Change, M.I.T., Cambridge, MA. 02139, USA

ABSTRACT

As policy makers consider strategies to reduce greenhouse gas emissions, they need to understand the available options and the conditions under which these options become economically attractive. This paper explores the economics of carbon capture and sequestration technologies as applied to electric generating plants. The MIT Emissions Prediction and Policy Analysis (EPPA) model, a computable general equilibrium model of the world economy, is used to model carbon capture and sequestration (CCS) technologies based on a natural gas combined cycle (NGCC) plant and an integrated coal gasification combined cycle (IGCC) plant. These technologies have been fully specified within the EPPA model for all regions of the world by production functions. We simulate the adoption of these technologies under scenarios with and without carbon taxes. The results illustrate how changing input prices and general equilibrium effects influence the global adoption of carbon sequestration technologies and other technologies for electricity production. Rising carbon prices lead first to the adoption of NGCC plants without carbon capture and sequestration followed by IGCC plants with capture and sequestration as natural gas prices rise.

INTRODUCTION

Heightened concerns about global climate change have aroused interest in carbon capture and sequestration technologies as a means of decreasing the growth rate of atmospheric carbon dioxide concentrations. Projects are already underway to research and implement such technologies in countries like the United States, Japan, Norway, and the United Kingdom. In the United States, the Department of Energy (DOE) is investigating the economic, technological, and social issues of carbon capture and sequestration technologies. Past research has focused on identifying research needs and assessing technical feasibility and engineering cost data [1,2]. More recently, economic modelers have sought to integrate knowledge about the economics of carbon capture and sequestration technologies into economic models [3,4,5]. This paper summarizes our analysis of two electricity generation technologies with carbon capture and sequestration as well as a generation technology without carbon capture and sequestration. David and Herzog [ 1] identified natural gas combined cycle generation with capture via amine scrubbing of the flue gas and integrated coal gasification combined cycle generation with pre-combustion capture of the carbon dioxide (CO2) as two of the most promising technological options for producing electricity with low CO2 emissions. The term carbon capture and sequestration (CCS) as used herein refers only to these two fossil power technologies and the subsequent capture and sequestration of the CO2. Many other energy sources and capture processes are often considered under the umbrella of carbon capture and sequestration

1084 technologies, but these options are not evaluated here. A third technology, natural gas combined cycle (NGCC) without sequestration, is modeled to represent advanced conventional generating technologies. This paper gives a brief overview of the method of analysis and the results obtained from introducing these technologies into multiple regions of a general equilibrium, global economic model. This analysis expands upon previous work [3] by introducing CCS technologies into multiple regions.

M E T H O D OF ANALYSIS

The M I T EPPA Model This analysis utilizes the MIT Emissions Prediction and Policy Analysis (EPPA) model described by Babiker, et al [6]. The EPPA model is a recursive dynamic multi-regional general equilibrium model of the world economy developed for the analysis of climate change policy. The current version of the model is built on a comprehensive energy-economy data set, GTAP-E [7], that accommodates a consistent representation of energy markets in physical units as well as detailed accounts of regional production and bilateral trade flows. The base year for the model is 1995, and it is solved recursively at 5-year intervals through 2100 to capture the long-term dynamics of resource scarcity and capital stock turnover. EPPA consists of twelve regions, which are linked by international trade, nine production sectors, and a representative consumer for each region (see Table 1). TABLE 1 EPPA REGIONSAND SECTORS Regions

Sectors

Annex B (United States, Japan, European Community, Other OECD, Eastern European Associates,Former SovietUnion) and Non-Annex B (Brazil, China, India, Energy Exporting Countries, Dynamic Asian Economies,and Rest of World). Coal, Oil, Refined Oil, Gas, Electricity, Energy Intensive Industries, Agriculture, Investment,and Other Industries.

Constant elasticity of substitution functions are used to describe production and consumption within each region and sector. In each time period the model solves these functions for a set of prices that clear supply and demand across all regions and sectors. The functions mathematically describe how the factors of production can be combined to produce output and how consumers trade-off among goods to maximize utility. Technologies are represented by production functions that use inputs in different combinations to produce their respective goods. In EPPA's conventional electricity sector, all fossil fuel-based generation technologies are represented by an aggregate production function. Specific technologies such as coal-fired plants or gas-fired turbines are not explicitly represented. Instead, these technologies are represented by conventional electricity's ability to switch among inputs of capital, labor, and fuels. Technologies for electricity produced from nuclear, hydro, biomass, wind and solar are explicitly represented.

Implementation of Carbon Capture and Sequestration Technologies For this analysis, separate production functions were added to EPPA for 1) coal power generation with CCS, 2) natural gas combined cycle power generation with CCS, and 3) natural gas combined cycle power generation without CCS. The NGCC without carbon capture and sequestration technology represents a technology that was not widespread at the time of preparation of the 1995 base year data, but is widely seen as the most likely technology to be installed where new capacity was needed. The electricity produced by each generation technology (conventional fossil fuel, nuclear, wind, gas without CCS, gas with CCS, and coal with CCS) is assumed to be a homogenous good and readily tradable within a region. Specification of the production functions consists of determining the cost of electricity from the technology, the factor shares of capital, labor, and energy required for electricity production, and the ability to substitute between the various factors of production. Costs CCS technologies are based on the bottom-up engineering cost analysis performed by David and Herzog [2] which assume small technical improvements prior to

1085 commercial availability in 2020. We view the full cost of electricity as composed of the components identified in Eqn. 1, which includes the unit costs of generation, transmission and distribution (T&D), sequestration, and value of carbon emitted to the atmosphere. Equation 1 can be used to see how, from a partial equilibrium perspective, different generation technologies compare as the price of carbon changes. (1)

CElectricity "- CG ..... tion + CT&D + Csequestration + IdgCarbon

Transmission and distribution costs and shares were derived from U.S. data [8]. Sequestration costs are assumed to be constant at $10 per tonne CO2, while emission costs are determined by a technology-specific emissions constant, K, and the price of carbon ($ per tonne carbon). The first column of Table 2 presents the total cost of electricity net emission costs based on these data. Comparing the electricity costs of these new technologies to the cost of conventional power in the U.S. at 66 mills per kilowatt-hour, we see that advanced gas generation without CCS is 16% less expensive. Gas and coal generation with CCS are respectively 8% and 25% more expensive. When introducing these technologies into other regions, we assume the ratio of the cost of electricity from the new technologies to conventional technologies remains constant across regions as do the shares of capital, labor, and fuel. The carbon price at which the capture technology and the NGCC technology, the lowest cost alternative, have the same total cost in the base year is shown in the last column of Table 2. At current natural gas prices, the natural gas technology with CCS becomes competitive at $190/tonne C, half that of the coal with capture technology. TABLE 2 TECHNOLOGYCOSTS Cost o f : Generation, Electricity Cost Ratio T&D, Sequestration of New Tech. to (mills/kWh) Conventional Tech. (66 mills/kWh) 0.84 Advanced Gas (NGCC) 55.3 71.0 1.08 Gas + Capture, Seq. 82.3 1.25 Coal + Capture, Seq. Technology

Emissions Constant, K (kg CO2/kWh) 0.337 0.037 0.073

Partial Equilibrium Carbon Entry Price vs. NGCC Technology ($/tonne C) $190 $380

In addition to the three inputs to production mentioned above, each technology is modeled to require a small share (1%) of a technology-specific fixed factor. The fixed factor represents various technology-specific inputs that limit the rate of penetration of a technology, but not the ultimate level of demand. The amount of fixed-factor is initially limited but grows as output expands. In the context of large-scale electricity generating technologies, this may be thought of an initially limited amount of engineering capacity to build and install new plants or a regulatory process that slows installation. We specify a technology's fixed factor supply grow endogenously with the level of output and posit a functional form with S-shaped growth. Without a fixed factor, technologies would immediately capture very high share of electricity production, an unrealistic proposition.

Capabilities The EPPA model allows us to evaluate the economic competitiveness of the CCS technologies as prices, output levels, and other conditions change in the general economy. The partial equilibrium cost comparisons in Table 2, while valid for considering a single plant for a set of reference prices, are not valid for considering the economy-wide potential for CCS technologies. When a carbon constraint is implemented, the prices of production inputs such as fuels and electricity change. Conversely, changes in prices, production activity, and general welfare due to CCS technology introduction can be investigated. The introduction of a competitive conventional technology such as natural gas combined cycle without capture yields similar information. EPPA also accounts for the stock nature of capital through an explicit vintaging of capital investments within the electric power sector. Vintaged capital retains the input shares it had when installed until it has depreciated; that is there is no ability to substitute among inputs once the capital is in place. Capital investments in EPPA are tracked by vintage and depreciate over a twenty year period. For this version, we

1086 further assumed that capital could not be reallocated out of a sector. While normally not an issue for other EPPA sectors [9], given the rapidly changing conditions in the electric sector with carbon policies we found a tendency for the solution to unrealistically allocate vintaged capital out of the CCS technology. By fixing capital to the technology, we more accurately capture the exit and entry dynamics of technologies [3]. Without fixed capital, a technology's output drops to zero when it becomes uneconomic since capital is not stranded in an utilized asset. Limitations

The representation of the electricity sector and the carbon sequestration technologies in the EPPA model has some limitations. First, since EPPA does not explicitly represent each power plant, it cannot represent the cost of retrofitting particular plants. Instead, the CCS technologies are modeled as new plant constructions. In reality, the distinction between a new plant and a retrofit is somewhat blurred. Extensive modifications to plants and structures at a particular site are not uncommon in the economy and could have advantages over trying to site a completely new plant, and it may be largely semantics as to whether a completely rebuilt plant at an existing site is a retrofit or a new plant (although the semantics have regulatory repercussions as US environmental regulations distinguish new sources from existing power plants emissions). Given the resolution within EPPA and the extent to which it affects the main results of concern, the distinction between a retrofit and a new plant primarily involves the difference in cost. In fact, only a fraction, ~, of each years investment is vintaged. The remaining stock (l-d?) remains malleable, reflecting the fact that there is an ability, albeit limited, to retrofit capital. Second, this same aggregation prohibits consideration of electricity market effects such as plant dispatch and transmission constraints. In ongoing work we are studying the implications of retrofitting on sequestration technology adoption.

SCENARIOS AND RESULTS The adoption of CCS technologies i n t h e United States is analyzed under a reference scenario without constraints on greenhouse gas emissions and under a scenario where a tax is placed upon carbon. Carbon taxation begins in 2010 at $50/tonne C and increases by $25/tonne C every five years reaching a maximum of $200/tonne C by 2040. The model results are compared to the reference scenario and to scenarios without CCS technologies. In the reference scenario, electricity production increases five fold over the modeling time frame from 24 trillion kilowatt-hours (TkWh) in 1995 to 120 TkWh in 2100 as shown in Figure 1. Conventional generation, primarily from coal, accounts for over 70% the electricity generation in each period. The share of advanced natural gas reaches 11% of total generation by 2100 equaling that ofhydropower. 140 120

• Conventional

[

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too

• Nuclear

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• Gas Capture

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• Coal Capture o 1995

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2040

2055

2070

2085

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Figure 1" Global Electricity Production- Reference Scenario

1087 Under the tax scenario, the contributions from the production technologies change substantially while the total electricity production in 2100 is reduced by only 6%. The advanced gas technology without capture expands rapidly from 2005 to 2040 as Figure 2 illustrates. With a lower initial cost of generation and less carbon production, this technology displaces conventional coal as the dominant electricity production technology by 2020. The advanced coal with capture technology enters the market in 2035 even though the carbon tax is only half of the partial equilibrium carbon entry price presented in Table 2. Rising natural gas prices drive this behavior as they make the gas technology much more expensive than that represented in Table 2. The higher gas prices also explain the lack of penetration by the gas with capture technology as it cannot compete with coal with sequestration. The rise in gas prices depends on specifics of the resource model in EPPA--if there were unlimited, low cost sources of gas then prices need not rise. EPPA bases its estimates of gas resources on USGS estimates of gas and includes a technology to produce synthetic gas from coal. 140 • Conventional 120

[] Adv. Gas

100

• Nuclear

~

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60

• Wind & Solar

40

•

I--

• Hydro

Biomass

,

• Gas Capture

20

• Coal Capture{ 0 1995 2010

2025 2040

2055

2070

2085

2100

Figure 2: Global Electricity Production- Tax Scenario The trends and timing of adopting the advanced gas technology without capture followed by advanced coal with capture are exhibited across all regions except for Japan, the European Community and India. Baseyear electricity prices in Japan and the European Community are at least 43% higher than the average prices of the other regions. High electricity prices inflate the effect of the electricity cost ratio parameter (see Table 2) and make the sequestration technologies economically unattractive. The advanced gas technology accounts for the majority of Japan's electricity after 2025. The European Community gradually replaces conventional coal technology with advanced gas until 2045 when the region reverts to conventional coal. At carbon prices of $300/tonne C, the European Community switches to advanced coal with capture after 2045. India, lacking substantial gas reserves, adopts the advanced coal with capture technology in 2035 and bypasses investments in advanced gas technologies.

CONCLUSIONS We derive some broad implications for the potential of CCS technologies from the modeling results. •

CCS technologies could play a substantial role in reducing carbon emissions, but would only be economically viable with policy constraints on carbon dioxide emissions.

•

Gas technology without carbon capture would be a cost effective near-term solution for electricity as it has relatively low carbon emissions, but given the representation of gas resources in the EPPA model, it is not competitive with coal with sequestration in the longer term.

•

Coal technology with carbon capture offers a cost effective long-term source of low carbon emitting electricity.

1088 •

Benefits of using the CCS technologies are seen through increased electricity production and lower electricity prices.

•

The availability of CCS technologies in the policy scenario leads to a smaller reduction in the demand for gas and coal than from the reference demands.

•

The primary uncertainties in these projections include the potential for technological improvements in CCS technologies, fuel prices, the level of economic growth and reference emissions, the carbon dioxide emission constraints, and economic viability of other low-carbon technologies such as nuclear and solar electric power technologies, and the details of policy implementation such as taxation and permit trading.

ACKNOWLEDGEMENTS

This work was conducted with support from both the U.S. Department of Energy's Integrated Assessment program within Biological and Environmental Research (BER) and the Office of Fossil Energy (DE-FG0299ER62748). The model underlying this analysis was supported by the U.S. Department of Energy's Integrated Assessment program within Biological and Environmental Research (DE-FG02-94ER61937), the U.S. Environmental Protection Agency (X-827703-01-0), the Electric Power Research Institute, and by a consortium of industry and foundation sponsors.

REFERENCES

David, J. and Herzog, H.(2000). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 973-978. David, J. (2000). S.M. Thesis, M.I.T., United States. McFarland, J., Herzog, H., Reilly, J. and Jacoby, H.D. (2001). In: Proceedings of the First National Conference on Carbon Sequestration, netl.doe.gov/publications/proceedings/01/carbon seq/2c3.pdf. Eckaus R., Jacoby, H., Ellerman, D., Leung, W. and Yang Z. (1996) Report No. 15, Joint Program on the Science and Policy of Global Change, MIT, Cambridge, MA. Kim, S. and Edmonds, J., (2000) Pacific Northwest National Lab report 13095. Babiker, M.H., Reilly, J.M., Mayer, M., Eckaus, R.S., Sue Wing, I. and Hyman, R.C. (2001) Report No. 71, Joint Program on the Science and Policy of Global Change, MIT, Cambridge, MA. Hertel T., (1997) Global Trade Analysis: Modeling and Applications. Cambridge University Press, Cambridge. U.S. Department of Energy (1999). Supporting Analysis for the Comprehensive Electricity Competition Act. Jacoby, H.D. and Sue Wing, I. (1999). The Energy Journal 20, 73.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1089

ECONOMIC BENEFITS OF A T E C H N O L O G Y STRATEGY AND R&D PROGRAM IN CARBON SEQUESTRATION S. Klara 1, D. Beecy2, V. Kuuskraa 3 and P. DiPietro4 United States Department of Energy, National Energy Technology Laboratory, 626 Cochrans Mill Road, P.O. Box 10940 Pittsburgh, PA 15236 USA z United States Department of Energy, Office of Fossil Energy, 19901 Germantown Road Germantown, MD 20874-1290 USA 3Advanced Resources International, 1110 N. Glebe Rd Suite 600 Arlington VA 22201 USA 4Energetics Incorporated, 901 D Street SW Suite 100, Washington D.C. 20024 USA

ABSTRACT

A modeling framework developed over the past several years for the U.S. Department of Energy's Carbon Sequestration Program examines future greenhouse gas (GHG) emissions scenarios and quantifies the economic benefits that result from an investment in carbon sequestration technology development. The CarBen (Carbon Sequestration Benefits) model combines results from a general equilibrium model with non-energy data and extrapolations through 2040 to provide a robust, transparent representation of the United States GHG emissions issue. The model estimates needed reductions in GHG emissions by calculating the difference between emissions under reference case and lower GHG emissions scenarios. The reduced emissions scenario is consistent with the Administration's Global Climate Change Initiative (GCCI), an 18% reduction in the GHG intensity by 2012 with steady progress toward stabilization thereafter. Under this scenario, U.S. GHG emissions are reduced by 107 million metric tons of carbon equivalent per year (MMTCE/yr) by 2012, and 1,100 MMTCE/yr in 2040. These emissions reductions are below a reference case that assumes significant technology progress. Further emission reductions from improved energy efficiency, from renewables and from non-CO2 mitigation are determined to be insufficient to meet the target reductions. The residual emissions reduction need is 31 MMTCE/yr in 2012 increasing to 800 MMTCE/yr in 2040. Sequestration options that can meet this need are identified and their domestic capacity and cost assessed. In the reduced emissions scenario for the United States, development and deployment of sequestration technology lowers the cumulative cost of GHG emissions reduction by $4 Billion through 2012 and $250 Billion through 2040.

INTRODUCTION

This paper is part of an ongoing effort by the U.S. Department of Energy's Carbon Sequestration Program to assess the economic benefits that may result from investments in carbon sequestration technology development. Earlier versions of this analysis were presented at GHGT-V and the First National Conference on Carbon Sequestration [ 1, 2]. The objective of DOE's sequestration technology development is to create lower cost options for GHG emissions reduction through voluntary challenges and market-based incentives. The benefits

1090 derive from cost altematives for GHG emissions abatement compared to existing altematives. The analysis is forward-looking and relies on assumed future scenarios regarding GHG emissions. As such, there exists an important feedback between the benefits analysis and DOE's Sequestration R&D portfolio. The Benefits analyses process seeks to identify lower cost options for meeting the Administration's current and longer term goals for reducing greenhouse gas emissions. For this, the process uses the CarBen (Carben Sequestration Benefits) model that has the capacity to project CO2 and non-CO2 GHG emissions to year 2040, under a variety of user-selected scenarios. The CarBen model can be run to: • • •

Identify costs and quantities of sequestration options under different GHG emission scenarios Provide information to evaluate the effects of potential incentives, promoting voluntary, market based participation in carbon mitigation, and Demonstrate the economic benefits of sequestration R&D.

The model is linked to a general equilibrium model of the U.S. economy and energy-sector (the National Energy Modeling System (NEMS), operated by the U.S. Energy Information Administration (EIA). In addition, the overall model draws on a series of mini-models and studies, such as the "Value-Added Geologic Sequestration" mini-model and EPA's surveys, projections and marginal abatement cost curves for non-CO2 greenhouse gases. The model incorporates technology progress, equivalent to "learning" in some models, consistent with EIA's NEMS methodology. Finally, the model incorporates a set of emissions reduction "backstop technologies" that are combined into a broad category called Advanced Sequestration. Rather than attempt to build that detail into the general equilibrium model, a "mini-model" of backstops using general equilibrium model data-- and other economic activity d a t a - runs the backstops models offiine. The solution is then tested to be sure it does not violate the general equilibrium model solution.

BENEFITS ANALYSIS

For the benefits analyses in this paper, the CarBen model is calibrated to EIA's 2002 Reference Case, which already incorporates significant advances in technology and reduced carbon intensity. The GHG emission reduction actions and their economic benefits in the Benefit Analysis are those beyond and above the Reference Case. Combined with the EIA data and forecasts are non-energy CO2 and non-CO2 GHGs from EPA and other sources [3,4]. Beyond 2020 we extrapolate emission trends and assume that GDP grows by 3% average per year. Carbon intensity decreases, but not as fast as the GDP grows, giving a net growth in GHG emissions of 1.5% per year. Under the reduced Emissions Scenario, the rate of growth in U.S. GHG emissions is slowed and then stopped according to the following schedule: • • •

2 0 0 2 - 2012: GHG intensity reduced to 152 mtC/$GDP, 18% below AEO 2002 reference case 2013 - 2020: Emissions growth reduced 50% below AEO 2002 reference case 2021 - 2040: GHG emissions stabilized at the 2020 emissions level.

This is consistent with significantly reducing GHG intensity by 2012 and making steady progress on the path to first slow and then stop the growth of our greenhouse gas emissions as set forth in the GCCI. Figure 1 illustrates the emissions gap between the reference case and Reduced Emissions Scenario. In 2012, the reduced emissions scenario will require a reduction of 107 MMTCE below the reference case. By 2040, the delta increases to 1,100 MMTCE. (As a point of reference, a new 400

1091 MW pulverized coal plant emits about 0.6 MMTCE/yr.) The Reduced Emissions Scenario represents significant reductions and a balance between economic and environmental objectives.

o000

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2020

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Figure 1: Reference Case and Reduced Emissions Scenarios

P O R T F O L I O OF T E C H N O L O G Y A portfolio of technologies are employed to meet the needed GHG emissions reduction. The likely contribution of each of the options is assessed by CarBen results presented in Figure 2. Note that the reference case scenario contains significant advancements in energy efficiency, renewable energy, and non-CO2 GHG mitigation. All further impacts contained in the reduced emissions scenario result from accelerated R&D and market incentives.

Efficiency & Renewables: Emission reduction benefits derive from DOE R&D in renewables, enduse efficiency, and supply-side technology efficiency improvements. Incremental emissions reductions are estimated from the EIA High Technology case [3], assuming approximately one-half the EIA High Technology gains scenario could be achieved economically with aggressive R&D.

Non-C02 GHG Mitigation:

Reduced emissions are included for GHGs other than CO2, e.g., methane, nitrous oxide, HGWPs. The emission reduction quantity was estimated based on EPA's "best available current technology" marginal abatement curves [5], and assuming that collaborative activities between DOE and EPA will lower the marginal costs of methane reductions from gas and oil production, coal mining, landfills, and other sources.

Forestry and Agriculture: Forests, grasslands, and other natural ecosystems offer potential for reducing net GHG emissions by their increasing carbon uptake using state-of-the-art technologies. Marginal cost curves developed by McCarl [6] were used to estimate the amount of these emission reductions. The quantity available at a given market price is assumed to be an ultimate value that will be achieved by 2040, with one quarter of this amount is deployed by 2012 and half by 2020. Additional emission reductions are assumed to occur from collaborative R&D between DOE and Agriculture.

1092 1,200 gl " 1,000 .o o n,,

.9

Sequestration

800

600

E tu 1.1.1 0 1-

e-Added Sequestration

400

, Agriculture ;PIG Mitigation 200 & Renew ables 0 2000

2010

2020

2030

2040

Figure 2: Contribution of Technologies to the GHG Emissions Reduction Need

Early Value-Added Geologic Sequestration: Technology options for this category include enhanced oil recovery and enhanced coalbed methane production. The ultimate CO2 storage capacity for these two types of formations in the contiguous United Sates is on the order of 20,000 MMTCE. Estimates of the amount of net COz sequestered per year at a given market price is derived from two studies prepared for the International Energy Agency's GHG Programme [7,8], and subsequent work conducted by one of the authors. At a shadow price of $25/tonC, EOR sequesters 10 MMTCE/yr and ECBM 2 MMTCE/yr in 2012. These results are reliant on R&D aimed at expanding the number of reservoirs that are economic at a given shadow price. Geologic sequestration relies on a supply of inexpensive captured CO2. It is well documented that capturing CO2 from low-purity streams, such as flue gas, is prohibitively expensive with current technology. However, a diverse set of industrial conversion processes exhaust a highly pure stream of CO2 as a natural consequence of operation. Studies conducted by the authors show that roughly 44 MMTCE/yr of easily captured CO2 is currently available from varied sources in the contiguous United States and that many of the CO2 vents are geographically co-located with opportunities for valueadded geologic sequestration. CO2 vents include cement manufacture, ammonia production, aluminum production, ethanol production, oxygen blown gasification, natural gas processing, petroleum refining, and helium production. The amount of high-purity CO2 that is vented is expected to grow due to over 100 MMTCE/yr by 2020 as existing capital stock is replaced with advanced fossil fuel conversion technologies.

Advanced Sequestration:

This area includes C02 storage in novel geologic formations, CO2 conversion, inexpensive capture from advanced fossil fuel conversion processes, reductions in emissions of non-CO2 gases beyond what is achieved with existing technology, and other advanced concepts. Novel geologic formations include different types of saline formations with the potential for in-situ chemical conversion of CO2. salt formations, salt domes, and depleted CO2 domes. It also includes hydrocarbon bearing shales and depleting gas reservoirs, both of which have the potential for value added by-products. Figure 2 shows a large amount of emissions reduction being supplied by advanced concepts beyond 2030, which justifies and motivates its robust R&D initiatives.

1093 MONETARY BENEFITS

The CarBen model estimates the monetary benefits of sequestration deployment in terms of a reduced cost of GHG emissions abatement. Benefits equal the difference between the cost of carbon sequestration technologies and displaced non-sequestration options, multiplied by the quantity of emissions reduction. In the reduced emissions scenario, application of value-added geologic and advanced sequestration technology reduce the cumulative cost of GHG emissions reduction by roughly $4 Billion through 2012 and $250 Billion cumulatively through 2040. In addition, the program works collaboratively with the U.S. Environmental Protection Agency and the U.S. Department of Agriculture to develop advanced options for non-CO2 emissions abatement and terrestrial sequestration, providing a shared monetary benefit on the order of $3 Billion cumulatively through 2020.

CONCLUSIONS An eventual transformation of the U.S. energy systems toward lower GHG emissions needs to be motivated by prices and markets, guided and paced by science, facilitated by new technology, and underpinned by supporting and coordinated domestic and international policies. Sequestration technology can facilitate and reduce the costs of this transition, creating innovative options for climate change mitigation. •

The President's Global Climate Change Initiatives will require reduction in GHG emissions of 107 MMTCE/yr below the reference case scenario in 2012.

•

The required GHG emissions reduction exceeds that which can be supplied by aggressive investments in advanced technologies to increase energy efficiency and renewable energy.

•

Finding cost-effective means of achieving the GCCI's goals will require a strategy of focused public/private R&D partnerships and performance-based market incentives.

•

Sufficient capacity in both geologic formations amenable to C O 2 storage and high-purity CO2 vents exists to meet the near-term residual GHG emissions reduction needs, assuming sequestration R&D is robust and successful.

•

Novel sequestration technologies and approaches are needed to meet mid- and long-term goals for carbon sequestration in the United States.

•

Cumulative benefits of near- and longer-term sequestration technologies are estimated to be roughly $4 Billion by 2012 and $250 Billion by 2040.

REFERENCES

1. Beecy, Kuuskraa, DiPietro. (2000) "The Economics Benefits of Carbon Capture and Sequestration R&D Under Uncertainty" Conference Proceedings of the 5 th International Conference on Greenhouse Gas Control Technologies. 2. Beecy, Kuuskraa, DiPietro. (2001) "U.S. Economic Benefits of Carbon Capture and Sequestration Given Various Future Energy Scenarios" Conference Proceedings of the First National Conference on Carbon Sequestration 3. U.S. DOE, Energy Information Administration. (2001) Annual Energy Outlook 2002 4. U.S. EPA (2002) U.S. Climate Action Report - 2002. 5. U.S. EPA (2001) Addendum to the U.S. Methane Emissions 1990-2020:2001 Update for Inventories, Projections, and Opportunities for Reductions, www.epa.gov/~h~info/reports/index.htm.

1094 6. McCarl, B., Schneider, U., et. al. (2001) "Economic Potential of Greenhouse Gas Emissions Reductions: Comparative Role for Soil Sequestration in Agriculture and Forestry" Conference Proceedings of the First National Conference on Carbon Sequestration 7. International Energy Agency Greenhouse Gas R&D Programme (2000) "Barriers to Overcome in Implementation of CO2 Capture and Storage (1) Storage in Disused Oil and Gas Fields." IEA Report Number PH3/22 8. International Energy Agency Greenhouse Gas R&D Programme (1998) Enhanced Recovery of Coal bed Methane." IEA/CON/97/27

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1095

PROSPECTS FOR CARBON CAPTURE AND SEQUESTRATION T E C H N O L O G I E S ASSUMING THEIR T E C H N O L O G I C A L LEARNING*" Keywan Riahi l'*, Edward S. Rubin 2, Leo Schrattenholzer l i International Institute for Applied Systems Analysis (IIASA), Schlossplatz 1,2361 Laxenburg, Austria 2 Carnegie Mellon University, Baker Hall 128A, 5000 Forbes Avenue, Pittsburgh, PA 15213, U.S.A

ABSTRACT This paper analyzes potentials of carbon capture and sequestration technologies (CCT) in a set of long-term energy-economic-environmental scenarios based on alternative assumptions for technological progress of CCT. In order to get a reasonable guide to future technological progress in managing CO2 emissions, we review past experience in controlling sulfur dioxide emissions (SOa) from power plants. By doing so, we quantify a "learning curve" for CCT, which describes the relationship between the improvement of costs due to accumulation of experience in CCT construction. We incorporate the learning curve into the energy modeling framework MESSAGE-MACRO and develop greenhouse gas emissions scenarios of economic, demographic, and energy demand development, where alternative policy cases lead to the stabilization of atmospheric CO2 concentrations at 5 50 parts per million by volume (ppmv) by the end of the 21 st century. Due to the assumed technological learning, costs of the emissions reduction for CCT drop rapidly and in parallel with the massive introduction of CCT on the global scale. Compared to scenarios based on static cost assumptions for CCT, the contribution of carbon sequestration is about 50 percent higher in the case of learning resulting in cumulative sequestration of CO2 ranging from 150 to 250 billion (109) tons carbon during the 21 st century. The results illustrate that assumptions on technological change are a critical determinant of future characteristics of the energy system, hence indicating the importance of long-term technology policies in reducing greenhouse gas emissions and climate change. INTRODUCTION The mitigation of adverse environmental impacts due to climate change requires the reduction of carbon dioxide emissions from the energy sector, the dominant source of global greenhouse-gas emissions. There are a variety of possibilities to reduce carbon emissions, ranging from the enhancement of energy efficiency to the replacement of fossil-based energy production by zero-carbon technologies. Most of the currently available mitigation technologies, however, are more costly and technologically inferior in some ways compared to the older and more "mature" fossil alternatives. Thus, there is an increasing interest among experts and policy makers in "add-on" environmental strategies to combine state-of-the-art fossil technologies with advanced technologies that capture carbon for subsequent sequestration. Such strategies, if successfully implemented, could enable the continuous use of fossil energy carries at low (or almost zero) emissions. Present costs for carbon capture technologies (CCT) to reduce emissions are between 35 and 264 $/tC (DOE, 1999), corresponding to a prohibitive cost increase for electricity of at least 25 $/MWh. Given the current costs, it is unlikely that CCT successfully enter the energy market, even if international

" This article is based on a more extensive study conductedjointly by IIASA and the Carnegie Mellon University. An earlier version of the paper was submitted to the Journal of Energy Economics in June 2002 (Riahi et al., 2002). This research was funded by the Integrated Assessment program, Biological and Environmental Research (BER), U.S. Department of Energy under Award Number DE-FG02-00ER63037.Any opinions, findings, conclusions or recommendation expressed herein are those of the authors and do not reflect the views of DOE, IIASA, or Carnegie Mellon University. " Corresponding author: KeywanRiahi is a Research Scholar at the International Institute for Applied SystemsAnalysis (IIASA), Schlossplatz 1, 2361 Laxenburg,Austria, Tel: +43-2236-807-491, Fax: +43-2236-807-488, Email: [email protected].

1096 agreements and efficient institutions for CO2 abatement would exist. Their pervasive diffusion will require substantial efforts to induce "technological learning", which could accomplish considerable cost reductions in the long run. Thus, in this paper we quantify the potential and achievable pace of technological learning for CCTs. We incorporate the learning into the energy modeling framework MESSAGE-MACRO (Messner and Schrattenholzer, 2000) and develop a set of global greenhouse gas emissions scenarios. Within this frame, we analyze the potential of CCTs in the context of other main mitigation options, such as fuel switching and enhanced energy conservation. ESTIMATION OF LEARNING CURVES F O R CARBON CAPTURE T E C H N O L O G I E S Generally, costs - and other indicators of technology performance - improve as experience is gained by producers (learning-by-doing) and consumers (learning-by-using). In order to get a reasonable guide to future technological progress of carbon capture technologies, past experience in controlling sulfur dioxide emissions (SO2) from power plants was reviewed (Taylor 2001). In particular, we have estimated learning rates of capital and operating cost reduction for the most common flue gas desulfurization (FGD) technology used at coal-fired power plants for SO2 capture. This technology (commonly known as SO2 "scrubbers") employs similar principles of operation as currently commercial CO2 capture systems that use chemical sorbents to remove CO2 from gas mixtures such as combustion products. For FGD systems, investment costs declined by 13% for each doubling of capacity worldwide, and this is therefore also the value we used to quantify the "learning curve" for CCTs. l SCENARIO D E V E L O P M E N T In order to obtain a plausible range of estimates for the deployment of CCT, we analyze two alternative baseline scenarios, depicting future worlds of increasing carbon emissions with presumably high impacts due to climate change. For each we develop two carbon mitigation scenarios (one with and one without CCT learning) aiming at the stabilization of atmospheric carbon concentrations at about 550 ppmv. The sequel of this section first presents the main characteristics of the respective baseline and carbon mitigation scenarios, proceeding later to the implications for CCT.

Baseline reference scenarios: Both baseline scenarios are selected from the set of 40 IPCC-SRES reference scenarios (IPCC-SRES, 2000). The B2-MESSAGE scenario (Riahi and Roehrl, 2000a) was selected because it is a kind of"middle of the road" (dynamics-as-usual) scenario. In addition, we selected the A2-MESSAGE scenario (Riahi and Roehrl, 2000b), since A2 portrays a fossil-intensive future characterized by heavy reliance on coal-based energy production. A2 and B2 are based on different assumptions of socioeconomic development, technological progress, and political change. They result in widely differing world energy systems, which are cost-optimal strategies under the given assumptions, and lead to a wide range of emissions levels (Figure 1). Assumptions for the main scenario drivers and results are presented in TABLE 1. Carbon mitigation scenarios: Two stabilization scenarios for each baseline were developed - one assuming constant costs for CCTs (A2550s, B2-550s), and one including learning for CCTs (A2-550t, B2-550t). The resulting CO2 emissions trajectories of the mitigation scenarios are shown in Figure 1. They are characterized by a peak of about 9 to 12 GtC around the middle of the 21 st century. Subsequently, emissions decline to slightly less than the 1990 emissions level (6 GtC) by 2100. The emissions in the baseline and the stabilization scenarios is quite similar through 2020, and only after 2020 do emissions reductions become pronounced. This is partly because power plants have lifetimes on the order of 30-40 years, which makes for slow turnover in the energy capital stock, and partly because of the temporal flexibility built into the concentration constraint.

i The "learning curve" equation is found to describe the decline in production costs for a wide range of manufacturing activities remarkably well (e.g., Dutton and Thomas, 1984; Naki6enovi6 et al., 1998; McDonald and Schrattenholzer, 2001). The relationship is given by an equation of the form: cost = a* (cumulative number of units produced) -b, where -b gives the slope for the improvement in costs (hours) in producing the units. On a log-log scale this equation plots as a straight line with slope -b. Generally, the "progress ratio" (2b) describes the ratio of current cost to initial cost after a doubling of production. Thus, a progress ratio of 0.80 meant that costs decreased by 20 percent for each doubling. Some authors therefore prefer the term "learning rate" for the latter quantity.

1097 The model is free to choose when and where to reduce carbon emissions, and later reductions coinciding with turnover in capital plant are usually cheaper, because of both technological progress and discounting 2. 30 ...............................

~ 20

IA 2

-

g,o~: 0 1900

t ," 1950

,

,

2000

2050

2100

Figure 1: Global carbon dioxide emissions in the A2 and B2 baseline scenarios, and in the respective stabilization scenarios with and without learning for CCT. TABLE 1 OVERVIEW OF SCENARIO DRIVERS AND RESULTS COMPARE WITH 1990 VALUES FOR POPULATION (5.3 BILLION), GDP (20.9 TRILLION (1990)US$), PRIMARY ENERGY (352 EJ), TOTAL CO2 EMISSIONS (6.2 GTC), CO2 CONCENTRATION (354 PPMV). Year Scenario

Baseline scenarios

Stabilization scenarios Static CCTs

Learning CCTs

A2

B2

A2-550s

B2-550s

A2-550t

B2-550t

Population (billion)

2050 2100

11.3 15.1

9.4 10.4

11.3 15.1

9.4 10.4

11.3 15.1

9.4 10.4

Global gross domestic product (trillion 1990US$)

2050 2100

82 243

110

235

81 236

109 231

81 237

109 231

Primary energy (E J) Cumulative carbon emissions (GtC) Cum ulative ca rbon sequestration (GtC) Carbon concentrations (ppmv)

2050 2100

1014 1921

869 1357

959 1571

881 1227

960 1636

1257

1990-2100 1990-21 O0

1527

1212

992

948

990

950

167

90

243

137

2100

783

550

550

550

550

-

603

883

Although the resulting emissions trajectories of the four stabilization scenarios are similar, we shall show below that the contributions of individual mitigation measures to bring down emissions differ significantly. T H R E E KINDS OF M I T I G A T I O N M E A S U R E S Applying the carbon concentration constraint to the baseline scenarios results in significant changes of energy demand and technology mix. Compared to the respective baseline scenarios, three principal contributors were identified by MESSAGE and MACRO as the most cost-effective route to meet the required stabilization target: •

Fuel switching away from carbon-intensive fuels such as coal.

•

Scrubbing and removing CO2 in power plants and during the production of synthetic fuels, mainly methanol and hydrogen.

•

Lower energy demand (enhanced energy conservation) of the stabilization case compared to the baseline counterpart, due to higher energy costs in the stabilization cases compared to their baseline scenario counterparts. The carbon reductions of each of the mitigation measures in the stabilization scenarios are summarized in TABLE 2. In all stabilization scenarios the largest reductions comes from structural changes in the energy system. To satisfy the carbon constraint, all mitigation scenarios make pronounced shifts to less carbonintensive primary-energy resources, and coal's share of primary energy decreases considerably. The second most important contribution is due to carbon capture and sequestration, where the emissions reductions are

2 For the scenarios presented in this paper, a discount rate of 5% was applied.

1098

particularly high in the case of learning CCT technologies. Cost improvements in the case of technological learning for CCT result in additional markets for carbon capture and enable comparatively higher shares of fossil energy production, compared to the cases with constant CCT costs (TABLE 2). As illustrated by the results, each of the three main mitigation measures is important, and none of the suggested mitigation options alone is sufficient to meet a 550 ppmv stabilization target. Hence, we conclude that effective mitigation strategies have to take into account the whole portfolio of technological possibilities, which includes also carbon capture with subsequent sequestration. TABLE 2 EMISSIONS REDUCTIONS (IN GTC) OF THE MAIN MITIGATIONMEASURES IN THE STABILIZATIONSCENARIOS FOR THE YEARS 2050 AND 2100. Demand reduction 2050 2100 Static CCTs A2-550s B2-550s Learning CCTs A2-550t B2-550t

Fuel switching 2050 2100

CO2 capture and sequestration 2050 2100

Total 2050

2100

0.3 0.3

3.6 1.3

2.2 1.4

12.5 3.9

0.5 0.3

5.8 3.0

3.0 2.0

21.9 8.2

0.3 0.3

3.7 1.5

2.1 1.1

9.5 4.0

0.4 0.3

8.9 4.0

2.9 1.7

22.0 9.5

COSTS OF CARBON CAPTURE AND SEQUESTRATION The capturing of CO2 accounts for about three-fourths of the total cost of a carbon capture, storage, transport, and sequestration system. The cost assumptions in the scenarios are based upon estimates from several recent studies (Rubin, et al., 2001; EPRI & USDOE, 2000; Simbeck,1999; Herzog,1999) assuming that CO2 is captured from flue gases by currently available chemical absorption systems. Generally, the capturing of CO2 is associated with efficiency losses of the power generation process, and additional costs for the carbon capture facilities. The (aggregated) carbon abatement costs for coal technologies resulting from our assumptions are 196 US$/tC, compared to 137 US$/tC for natural-gas (both figures including transportation and disposal). 3 In the stabilization scenarios with constant costs (A2-550s, B2-550s), we assumed that the capital costs for CCTs remain constant over time. In contrast, in the case of learning CCTs (A2-550t, B2-550t), we assumed that their costs decrease with accumulated experience in CCT construction. The development of carbon reduction costs as a function of cumulative installed CCT capacities in the scenarios is illustrated in Figure 2a. Due to technological learning, CCT costs drop rapidly in the stabilization scenarios, leading to cost reductions by a factor of four until the end of the century. In line with the development of costs, CCT technologies diffuse pervasively into the energy markets, accomplishing the continuous use of fossil fuels at relatively modest costs and low carbon emissions. Total reduction costs for natural gas technologies drop to 34-38 US$/tC, and those of coal technologies to 41-61 US$/tC (Figure 2a). 4 CCT M A R K E T SHARES IN T H E E L E C T R I C I T Y S E C T O R The scenario's market shares of CCT technologies are the result of complex interactions between demandpull to supply-push activities. On the demand side, the carbon concentration limit enforces the introduction of new and advanced technologies with low carbon intensities. On the supply side, increasing returns from induced technological leaming of CCTs, pushes their market penetration (in the t-scenarios) from the supply side. Together, this results in very successful penetration of CCT technologies in the scenarios with technological learning, compared to scenarios with static cost assumptions (Figure 2b). Initially, CCTs are expensive and limited in their application. They have to first prove themselves during the demonstration phase where performance rather than costs is the overriding criterion. Then subsequent improvements and

3 Costs of carbon removal in synthetic fuels production (and from IGCC) were assumed to be 46 US$/tC (inclusive transportation and disposal). For transportation and disposal we assumed that captured CO2 is transported in liquid state, through 250 km of pipeline and disposed of in geological formations. The cost for CO2 transportation is based on estimates from the lEA (1999), assuming originally a distance of 500 km at 45 $/tC. Here, half the distance and an economy of scale factor of 2/3, which results in 28 $/tC of transport plus disposal cost is assumed. 4 The development of the carbon reduction costs for CCTs depend also on the regional resource availability and the development of fuel costs. In addition, assumptions on technological change for the power plants themselves influence the carbon reduction costs of CCTs. A sensitivity analysis using different initial costs for CCTs suggests that the learning rate might be the most decisive factor, not only for the costs, but also for the successful diffusion and dissemination of CCTs (given a specific carbon constraint).

1099

cost reductions lead to a wider application. Finally, growth rates slow down as markets become saturated. The diffusion of CCTs proceeds along a typical S-shaped pattern: slow at the beginning, followed by accelerating growth that ultimately slows down as markets become saturated. Comparing the diffusion of CCTs in scenarios with learning (A2-550t, B2-550t) with those assuming constant costs of these technologies (A2-550s, B2-550s) shows that the market penetration of CCTs is accelerated due to technological learning. Particularly, the carbon capture from coal technologies benefits considerably from the learning effect, leading to global market shares of more than 90 percent in 2100 (compared to 60-70 percent in the case of static costs). At the end of the century, almost all fossil power plants are equipped with carbon capture technologies in the case of learning (Figure 2b). The resulting CO2 emissions from coal and natural gas-based power generation are also shown in Figure 2b. The CO2 emissions path in the scenarios follows an inverse U-shaped pattern similar to environmental Kuznets curves, observed for other pollutant emissions in the past, such as sulfur (Grtibler, 1998). After initial growth, CO2 emissions peak around the middle of the century and decline later, when the carbon capture and sequestration technologies gain considerable market shares. Most notably, until the end of the century, global CO2 emissions from coal and gas power generation decreases by more than a factor of three, while power generation from these technologies grow three to five times their present production (about 27 EJ). --i

1000

• -

-

-:.

.

.

.

.

.

.

.

b)

.

100%

4000

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I C O 2 ernissions~

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.............................................

) cZ~I . . . . .

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~

3500

,000

N

F lOO

25o()

.........................

g,

i_

.

.........

lOOO0

lO

1

10

100

1000

Cumulative Installed capacities with carbon scrubbing In GW(e), 2000.2100

10000

0*/. ' 2000

~ 2020

2040

o 2060

2080

2100

Figure 2: (a) Technological learning of carbon capture technologies in the A2-550t and B2-550t scenarios, illustrated as decreasing specific carbon reduction costs over accumulated experience (cumulative installed power generation capacities). (b) Market penetration of "learning" CCT technologies for natural-gas and coal power plants in the A2550t and B2-550t scenarios (left-hand axis). Dashed lines depict the development in the A2-550t scenario, and uninterrupted lines in B2-550t. Also shown are the aggregated CO2 emissions from coal and natural-gas power generation in the respective scenarios (right-hand axis). The cumulative carbon sequestration in the scenarios - from 1990 to the 2100 - are shown above in TABLE 1. Generally, the amounts scrubbed depend strongly on (1) the socio-economic and technological assumptions in the baseline scenarios; and (2) the assumptions with respect to technological learning for CCT technologies. Cumulative carbon sequestration is higher in the case of the A2 scenarios compared to B2, and higher in scenarios with learning CCTs than in those with static cost assumptions. 5 In the case of learning CCT's cumulative carbon emissions from 1990 to 2100 range between 137 and 243 GtC. This corresponds to a 50 percent increase of sequestration due to learning effect for CCTs, compared to the scenarios with static costs (90 to 167 GtC). 6

5 Since the A2 baseline depicts a future of heavy reliance on coal technologies, cumulative carbon sequestration is particularly high in A2, calling for environmentally compatible solutions that permit the continuous use of coal at low carbon emissions. In contrast, fossil-based power generation plays a less prominent role in the B2 baseline scenario, and is mainly dominated by advanced natural gas technologies, in particular gas-combined-cycle. Hence, in A2 coal scrubbers dominate, while in B2 natural~ as scrubbers account for the bulk of the reductions. The amount of carbon emissions that has been captured in the scenarios is well below the maximum potential of storage capacity of depleted oil and gas fields alone (Herzog 2001, Riahi et al., 2002). Nevertheless, it still has to be proved, whether all reservoirs proposed for carbon sequestration are effective, safe and environmentally sound.

1100

S U M M A R Y AND CONCLUSIONS Our analysis shows that the timing, costs, and contribution of carbon mitigation measures strongly depend on (1) the socio-economic and technological assumptions in the baseline scenario, and (2) the assumed learning potential of carbon capture and sequestration technologies. Assuming that CCT technologies learn at a similar pace as SO2 abatement technologies in the past, the long-term reduction potential for CCT is vast; in our scenarios ranging between 140 and 250 GtC of cumulative CO2 sequestration (from 1990 to 2100, assuming a stabilization target of 550 ppmv). This is particularly due to large-scale investments into CCT and the accumulation of experience, which leads to rapid cost decreases of these technologies. Even though their widespread deployment requires decades to come, we conclude that carbon capture and sequestration is one of the obvious priority candidates for long-term technology policies and enhanced R&D efforts to hedge against the risk associated with high environmental impacts of climate change. Our scenario analysis also showed that the capturing of carbon with subsequent sequestration might not be sufficient to meet a 550 ppmv stabilization constraint (in the year 2100), even in the case of a very successful market penetration for CCTs. In addition to carbon sequestration, reaching this goal must also include better energy efficiency and the increased use of low-carbon emitting energy sources, in particular fuel switching, primarily away from carbon-intensive coal to low or zero-carbon fuels. Acknowledging the major differences between scenarios with learning CCTs and those with static cost assumptions leads us to two important conclusions. First, improved future models should be capable of characterizing future changes in cost and performance resulting from technology innovation (learning). Second, climate policies need to be extended to include technology policies, in order to make the diffusion of environmentally sound technologies operational in the long run. This calls particularly for early action to accomplish the required cost and performance improvements in the long term, including the creation of niche markets, the development of small-scale demonstration plants, and targeted R&D. REFERENCES 1. Dutton, J.M., and Thomas, A. 1984. Treating progress ratios as a marginal opportunity. Academy of Management Review, 9(2):235-247 2. EPRI& USDOE, 2000. Evaluation of Innovative Fossil Fuel Power Plants with CO2 Removal, EPRI, Palo Alto, CA 3. Grtibler, A., 1998, A review of global and regional sulfur emissions scenarios. Mitigation and Adaptation Strategies for Global Change, 3(2-4), 383-418. 4. Herzog,H.J., 2001. What Future for Carbon Capture and Sequestration. Environmental Science and Technology, Volume 35(7), 148A-153A. 5. IPCC(Intergovernmentai Panel on Climate Change), 2000. Naki~enovi~N., J. Alcamo, Davis, G., de Vries, B., Fenhann, J., et al. (2000), Special Report on Emissions Scenarios (SRES), A Special Report of Working Group III of the Intergovernmentai Panel on Climate Change, Cambridge UniversityPress, Cambridge, UK. 6. McDonald, A. and Schrattenholzer, L., 2001. Learning curves and technology assessment, Special Issue of the International Journal of Technology Management, Vol. 8, No. 23. 7. Messner, S., and L. Schrattenholzer. 2000. MESSAGE-MACRO: Linking an energy supply model with a macroeconomic module and solving it iteratively, Energy 25:267-282. 8. Nakicenovic N, Grt~bler A, and McDonald A (eds.). 1998. Global Energy Perspectives. Cambridge University Press, Cambridge, UK, ISBN 0521642000. 9. Riahi, K., Roehrl, R.A., 2000a. Greenhouse Gas Emissions in a Dynamics-as-usual Scenario of Economic and Energy Development. Technological Forecasting and Social Change, Vol. 63(3). 10. Riahi, K., Roehrl, R.A., 2000b. Energy technology strategies for carbon dioxide mitigation and sustainable, Environmental Economics and Policy Studies, Springer, Tokyo, 3(2), pp. 89-123. 11. Riahi, K., Rubin, E.S., Taylor, M.R., Schrattenholzer, L., Hounshell, D., 2002, Technological learning for carbon capture and sequestration technologies, Energy Economics (forthcoming). 12. Rubin, E.S., A.B. Rao and M.B. Berkenpas, 2001. A multi-pollutant framework for evaluating CO2 control options for fossil fuel power plants. Proceedings of First National Conference on Carbon Sequestration, US Department of Energy, Washington, DC. 13. Simbeck, D., 1999. A portfolio selection approach for power plant co2 capture, separation and r&d options, Proc. of 4th Int'l. Greenhouse Gas Control Technologies, Elsevier Science Ltd. 14. Taylor, M., 2001. The Influence of Government Actions on Innovative Activities in the Development of Environmental Technologies to Control Sulfur Dioxide Emissions from Stationary Sources. Ph.D. Thesis, Carnegie Mellon University, Pittsburgh, PA, Jan 2001. 15. U.S. DOE (Department of Energy), 1999. Carbon Sequestration - Research and Development. U.S. Department of Energy, Washington DC 20585, (www.doe.gov/bridge).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1101

CO2 STORAGE AND SINK ENHANCEMENTS: DEVELOPING COMPARABLE ECONOMICS B.R. Bockl, R.G. Rhudy2, and H.J. Herzog 3 ~Public Power Institute, Tennessee Valley Authority, Muscle Shoals, AL, USA 2Electric Power Research Institute, Palo Alto, CA, USA 3Laboratory for Energy and the Environment, Massachusetts Institute of Technology, Cambridge, MA, USA

ABSTRACT This paper reports on a project that compared the economics of major technologies and practices under development for CO2 storage and sink enhancement, including options for storing captured CO2, such as active oil reservoirs, depleted oil and gas reservoirs, deep aquifers, coal beds, and oceans, as well as the enhancement of biological sinks such as forests and croplands. For the geologic and ocean storage options, CO2 capture costs from another project were added to the costs of CO2 storage estimated in this project to provide combined costs of CO2 capture and storage. Combined costs of CO2 capture and storage were compared with CO2 sink enhancement costs on a life-cycle greenhouse gas (GHG) avoided basis. The CO2 storage and sink enhancement options compared in this project differ greatly in the timing and permanence of CO2 sequestration. In addressing the timing and permanence issue, a 100-year planning horizon was assumed and the net present value of both costs and revenues was considered. The methods for comparing the economics of diverse CO2 storage and sink enhancement options are overviewed and representative base-case costs of storage and sink enhancement options are compared.

INTRODUCTION In order to plan for potential CO2 mitigation mandates, utilities need better cost information on CO2 mitigation options, especially storage and sink enhancement options that involve non-utility operations. One of the major difficulties in evaluating CO2 storage and sink enhancement options is obtaining consistent, transparent, accurate, and comparable economics. This paper reports on a project that compares the economics of major technologies and practices under development for CO2 storage and sink enhancement, including options for storing captured COz, such as active oil reservoirs, depleted oil and gas reservoirs, deep aquifers, coal beds, and oceans, as well as the enhancement of biological sinks such as forests and croplands.

CO2 CAPTURE AND STORAGE

Methodology Capture costs were obtained from a DOE/EPRI [1] project that evaluated several CO2 capture technologies. Integrated gasification combined cycle (IGCC) cases were used as the basis for the

1102 capture component of this project. Costs of CO2 capture were based on differences between reference and capture IGCC plants. Revenue requirement (RR) methodology which is applicable to regulated utilities was used by DOE/EPRI [1] to estimate costs of CO2 capture. Revenue requirement methodology was also used in this project to estimate CO2 storage costs so that capture and storage costs could be combined on an equal basis. Storage options were sized to accommodate the CO2 captured (2.158 Gg CO2/year) from the IGCC CO2 capture plant noted above, 404 MW (net), operating at 80 percent capacity factor; 90 percent of the CO2 produced was captured.

Revenue Requirement Methodology In the DOE/EPRI [1] project, a levelized RR ($/yr) was calculated for each year of the 20-year book life of the plant as follows: Levelized RR = Levelized Carrying Charge (LCC) + Expenses = Levelized annual cost of

electricity

(1) where LCC = Total Plant Cost (or TPC) x Levelized Carrying Charge Factor (or LCCF), and Expenses include O&M and fuel costs. The TPC includes process facilities capital, general facilities capital, engineering and home office overhead, project and process contingencies, and miscellaneous expenses generally included under owners costs. Assumptions in the DOE/EPRI [ 1] project resulted in a LCCF of 0.15 and an after-tax discount rate of 6.09%. In calculating the costs of storing captured CO2, the RR methodology for CO2 capture was generalized to accommodate options for enhanced revenues from CO2 storage such as enhanced oil recovery (EOR) and enhanced coal bed methane recovery (ECBMR): Levelized RR = LCC + O&M costs - Enhanced revenues = Levelized annual net cost of storing CO2 (2)

GHG Bases for Calculating Costs Costs ($/Mg C equivalent) were estimated on CO2 captured, CO2 avoided, and life-cycle (LC) GHG avoided bases. The LC GHG avoided basis included all significant GHG avoided from cradle to grave, but did not include externalities (i.e., damage assessments). Carbon dioxide avoided and LC GHG avoided via CO2 capture were estimated based on the difference in CO2 and LC GHG emissions from reference and capture plants. Carbon dioxide and LC GHG emissions were also estimated for each of the CO2 storage options evaluated, and CO2 and LC GHG emissions avoided were estimated for CO2 capture and storage combined. Combined costs of CO2 capture and storage were compared with costs of sink enhancement options, forestry and cropland, on a LC GHG avoided basis.

Accounting for Timing Differences: C02 Storage vs. Sink Enhancement The timing and permanence of GHG abatement and the timing of costs differ greatly between CO2 capture/storage options and CO2 sink enhancement options. In addressing the timing and permanence issue, a 100-year planning horizon was assumed and CO2 removals and emissions/leaks were treated as separate events. The idea is that when one removes a ton of CO2, one receives the current price of CO2. When a ton of CO2 is released, the owner of this CO2 must then purchase a credit from elsewhere at the current price. This approach assumes that CO/prices will be set as a result of government policy either through market mechanisms (e.g., a cap and trade system) or in the form of a tax (e.g., a carbon tax). With these assumptions, the cost of CO2 storage and sink enhancement ($/Mg C equivalent) was calculated as a breakeven C price ($/Mg C equivalent). A breakeven C price was calculated for each CO2 storage and sink enhancement scenario by setting the sum of discounted C revenues (C price times the amount of C removed)

1103 equal to the sum of discounted C storage or sink enhancement costs for the 100-year planning horizon and solving for a breakeven C price.

Base Case Assumptions Base cases for the geologic storage options assumed a pipeline C02 transportation distance of 100 km from the power plant to the storage operation and a well depth of 1220 m for all geologic options except enhanced coalbed methane recovery in which case a well depth of 610 m was assumed. In calculating enhanced oil and gas revenues, wellhead oil and gas prices of $15 per bbl and $2.00 per MBtu, respectively, were assumed. The ocean pipeline and ocean tanker options assumed a pipeline CO2 transportation distance of 100 km from the power plant to the ocean shore and a pipeline or tanker CO2 transportation distance of 100 km from the shore to the ocean injection point. An injection depth of 2000 m was assumed for both ocean options. The ocean options were designed on a scale to accommodate CO2 from three base-case IGCC power plants. Results

GHG Bases for Calculating Costs The IGCC capture plant captured 2.158 Gg (million tonnes) CO2 per year. Compared with the IGCC reference plant, the IGCC capture plant avoided 1.824 Gg direct CO2 emissions per year, and avoided 1.807 Gg LC GHG CO2 equivalents per year. Carbon dioxide and LC GHG emissions from the CO2 storage operations were relatively small (not presented) and were subtracted from CO2 avoided during capture and LC GHG emissions avoided during capture, respectively, to get CO2 avoided via capture and storage combined and LC GHG emissions avoided via capture and storage combined. Costs Carbon dioxide capture costs were $54/Mg C eq. CO2 captured, $63/Mg C eq. C02 avoided via capture, and $64/Mg C eq. LC GHG avoided via capture. Carbon dioxide capture + net storage costs are presented in Table 1 for base cases on C equivalent stored, C equivalent CO2 avoided via capture and storage, and C equivalent LC GHG avoided via capture and storage bases. These costs were calculated on an NPV basis for years 1-100. Costs are very similar on CO2 and LC GHG avoided bases and are significantly higher on these two bases than on the stored basis. The two lowest-cost storage processes are enhanced oil recovery and enhanced coalbed methane recovery, both of which provide enhanced revenues that partially offset costs of COa storage.

Storage Process

TABLE 1 co2 CAPTURE+ NET STORAGECOSTS FOR BASECASES $/Mg C eq. $/Mg C eq. C02 stored C02 avoided

$/Mg C eq. LC GHG avoided

Depleted Gas Reservoir Depleted Oil Reservoir Deep Saline Aquifer Enhanced Oil Recovery Enhanced Coalbed Methane Recovery

72 68 65 12

85 80 77 15

86 81 77 15

34

41

41

Ocean Pipeline Ocean Tanker

74 118

86 141

89 143

1104 FOREST MANAGEMENT Case Studies Additional C can be sequestered in forests by establishing new plantations, restoring existing forests, or by avoiding deforestation.

Cases studies representing a wide range of management types, trees, and geographic locations were included (Table 2). TABLE 2 FORESTRYCASE STUDIES

Type of Management

Type of Trees

Country/region

Plantation Plantation Plantation Restoration Restoration Agro-forestry Avoidance of deforestation

Loblolly pine Douglas Fir Spanish Cedar Pine-oak Miombo Mango-Tamarind Various

USA (South) USA (Pacific NW) Mexico Mexico Southern Africa India (South) Mexico

Costs Base-case costs ($/Mg C eq.) are presented in Figure 1 on an aboveground basis (costs/aboveground C) and a life-cycle GHG avoided basis with product revenues net costs after product revenues/aboveground C + below ground C + product C + non-CO2 GHG C eq.). These two accounting bases bracket the costs ($/Mg C eq.) for each of the cases. Costs are on an NPV basis, 100-year planning horizon. The Mango-Tamarind costs are relatively high on an aboveground basis because costs for the ago-forestry system are high and no credit is taken for the relatively high value agricultural products. The Mango-Tamarind costs are relatively low on the aboveground C + below ground C + product C + non-CO2 GHG C eq. basis because credit is taken for both more C and products that more than offset costs.

200 m,m

o=

150

"=

100

E

5o o

~ @

-50 -lOO

-150 -200

! Aboveground

i

• Aboveground+ Below ground + products - non CO2 GHGs i

Figure 1: Base-case costs for forestry cases

1105 CROPLAND VIA REDUCING T I L L A G E Reducing tillage on cropland slows the rate of organic matter decomposition and increases soil organic matter levels until a new equilibrium level is attained (typically about 20 to 30 years after shifting from intensive tillage to no tillage). Carbon is sequestered in the added soil organic matter. Reducing tillage reduces equipment and fuel use, increases herbicide use, and can affect the amount of nitrogen fertilizer required and N 2 0 emissions from the soil. Costs to a utility are an adoption incentive to get farmers to switch from intensive tillage to no-tillage, transaction costs for aggregating and brokering GHG credits, and monitoring costs for assuring that contractual obligations are fulfilled. Case Studies Case studies for converting from intensive-tillage to no-tillage agriculture were conducted for the following United States agricultural regions and cropping systems: • Central Corn Belt (corn/soybean rotation* and continuous corn*) • Central Great Plains (grain sorghum/soybean rotation and continuous grain sorghum) • Western Great Plains (wheat/fallow* and wheat fallow to wheat/sorghum/fallow) • Mississippi Corridor (corn/soybean rotation and continuous cotton*) These cases represent the range of costs for CO2 sink enhancement expected due to converting from intensive-tillage to no-tillage on U.S. cropland. Costs ($/Mg C equivalent life-cycle GHG avoided) are a function of the adoption incentive a utility would have to pay farmers to get them to switch from intensive tillage to no tillage system, transaction costs, monitoring costs, and changes in C sequestered in soil organic matter, N20 emissions from soil, and GHG emissions from crop production inputs. Cases noted with an asterisk represent the range of costs expected from converting from intensive tillage to no tillage on U.S. cropland.

Costs Base-case costs are presented in Table 3 for cases that represent the range of base-case costs expected from converting from intensive tillage to no tillage on U.S. cropland. These results are presented for cases in which an annual adoption incentive is paid for 5, 10, 15, or 20 years. These costs are based on the assumption that, due to soil quality and crop yield benefits that develop over time, a farmer would continue the no-till practice after the adoption incentive stops.

TABLE 3 BASE-CASE COSTS OF CO2 SINK ENHANCEMENT--INTENSIVE TILL TO NO TILL

Corn/soybean Incentive period, years 5 10 15 20

30 48 62 72

Continuous corn Wheat/fallow Continuous cotton Cost (NPV basis, 100-year planning horizon) $/Mg C equivalent life-cycle avoided 30 32 54 51 49 88 66 61 113 77 71 132

CONCLUSIONS

For CO2 storage options, costs are very similar on a CO2 avoided basis and a LC GHG avoided basis and costs on both of these bases are significantly higher than on a CO2 stored basis. Base-case cost ranges on a life-cycle GHG avoided basis are as follows: • CO2 capture + net storage costs ($15 to 145/Mg C equivalent avoided)

1106 •

•

Forest management --Aboveground basis ($10 to 175/Mg C equivalent avoided) --Aboveground + below ground + products basis ($-160 to 55/Mg C equivalent avoided) Cropland via reducing tillage --Mid-range, 10-year adoption incentive period ($50 to 90/Mg C equivalent avoided)

These base-case cost ranges are non site specific, mid-range estimates to be used as a general indication of costs for CO2 storage and sink enhancement options. Costs of capturing and storing CO2 will vary from the base-case estimates in this paper depending on the capture technology used, distance between the capture plant and storage operation, and characteristics of the storage reservoir. Costs of improved forest management for the types of cases presented will vary with forest productivity, land and labor costs inherent in a location, and other local factors. Costs of reducing tillage on US cropland will also vary with local factors. Sensitivities to key variables were included in the final report. Avoidance of deforestation and enhanced oil recovery are the least cost options in situations where they are practical.

ACKNOWLEDGEMENTS The authors wish to acknowledge US DOE National Energy Technology Laboratory for primary funding of the project on which this paper is based and the other team members on the subject project team who were instrumental in assessing the economics of the CO2 storage and sink enhancement options reported in this paper: Mike Klett, Parsons Infrastructure & Technology Group; Gemma Heddle, Massachusetts Institute of Technology; John Davison, IEA Greenhouse Gas R&D Programme, Daniel De La T0rre Ugarte and Chad Helwinckel, Univeristy of Tennessee; Dale Simbek, SFA Pacific; and George Booras, Electric Power Research Institute.

REFERENCES 1. DOE/EPRI. 2000. Evaluation of innovative fossil fuel power plants with CO2 removal. EPRI., Palo Alto, Califomia; U.S. Department of Energy-Office of Fossil Energy, Germantown, Maryland, and U.S. Department of Energy/NETL, Pittsburgh, Pennsylvania: 1000316.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1107

CARBON M A N A G E M E N T STRATEGIES FOR EXISTING U.S. GENERATION CAPACITY: A VINTAGE-BASED APPROACH RT Dahowski I and JJ Dooley2 1 Battelle- Pacific Northwest National Laboratory P.O. Box 999 / Mail Stop K6-10, Richland, WA 99352 z Battelle- Pacific Northwest National Laboratory 8400 Baltimore Avenue, Suite 201 College Park, Maryland, 20740

ABSTRACT

This paper examines the existing stock of fossil-fired power generation capacity in the United States within the context of climate change. At present, there are over 1,337 fossil-fired power generating units of at least 100 MW in capacity, that began operating between the early 1940's and today. Together these units provide some 453 GW of electric power, and simply retiring this stock early or repowering with advanced technology as a means of addressing their greenhouse gas emissions will not be a sensible option for them all. Considering a conservative 40-year operating life, there are over 667 fossil-fired power plants, representing a capacity of over 291 GW, that have a minimum of a decade's worth of productive life remaining. This paper draws upon specialized tools developed by Battelle to analyze the characteristics of this subset of U.S. power generation assets and explore the relationships between plant type, location, emissions, and vintage. It examines the economics of retrofit capture technologies and the proximity of these existing power plants to geologic reservoirs with promise for long-term storage of CO2. The average costs for retrofitting these plants and disposing of their CO2 into nearby geologic reservoirs are presented.

INTRODUCTION The ultimate objective of current intemational efforts to address climate change, stated succinctly by the United Nations Framework Convention on Climate Change (UNFCCC) [1], is the "stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system." Wigley et al. [2] have shown that in order to achieve this goal, carbon emissions must be substantially reduced over the course of this century, and must be virtually eliminated going further into the future. Fulfilling the objective of the UNFCCC will require a long-term and fundamental transformation of the global energy system. Progressing towards this long-range goal of a net zero-emitting global energy sector requires that some actions be taken in the near term to slow the increase in global CO2 emissions. It is not unreasonable to believe that a significant fraction of this early mitigation effort can be achieved through aggressive deployment of existing renewable energy technologies and continued advancements in energy efficiency. Yet a growing body of research suggests that these steps alone will not be enough to move the global energy system onto a pathway towards stabilizing atmospheric greenhouse gas concentrations (see [3], for

1108 example). Particularly in the U.S., where over 40% of total CO2 emissions are attributable to the electric power sector [4], it can be expected that some attention will need to be paid to reducing the CO2 emissions from existing power plants. Geologic disposal of CO2 is one such method that holds significant potential for addressing these emissions [5].

U.S. FOSSIL-FUELED P O W E R GENERATION STOCK According to the most recent data contained within the Battelle CO2-GIS [6], there are currently more than 1,337 large fossil-fired generating units operating in the U.S. with a total capacity of 453 GW. Total annual CO2 emissions from these plants exceed 2.27 billion tons. The range of vintages for these plants spans the period from 1941 to 19991. Figure 1 shows the breakout of fossil-fueled power generation capacity by unit vintage and fuel type. The number in parentheses above each bar indicates the total number of operating units within each vintage category. This figure illustrates the dominant role that coal plays in U.S. fossil-fired power generation. The majority of new plants that came on-line from the 1950's through the 1980's were coal fired, with average plant sizes increasing over that time period. However, beginning in the 1990's a trend towards the increasing use of smaller natural gas fired technology developed and has continued through today. Projections of planned capacity additions through the end of this decade, using data compiled for a separate analysis [9], indicate that this trend is likely to continue. Although it remains to be seen how many of these plants will actually be built, the data indicate a possible resurgence in power plant construction over the coming decade, with most units being natural gas fired. 350 -

(471) ] I

300

----I

i! 250 -

t I

,oot.I 50

1940's

(')

II

o~

I,,.I

II

1950's

1960's

1970's

(,,~)

(,~)

: 1980's

1990's

I--IJ 2000's Planned Through 2 0 1 0

Figure 1: Installed U.S. Fossil-Fired Capacity by Fuel Type & Vintage (Number of Units in Parentheses) While it may be quite realistic to assume that many of the older power plants will be shut down, replaced, or repowered with new advanced technology (such as IGCC) in the face of climate and other environmental concerns, it is naYve (and would prove terribly disruptive to the U.S. economy) to believe that the entire stock of existing fossil-fired plants will be replaced or upgraded in this fashion. A large portion of the i The last complete update of the BattelleCO2-GIS power plant database occurred in July 2000, covering fossil-firedgenerating units with a capacityof at least 100 MW, operating within the United States as of early 1999. EIA data [7,8] suggests that over 152 additionalunits have been built and begun operating since, and plans are underwayto update the Battelle CO2-GIS to reflect these more recent data.

1109

existing stock is less than 30 years old and will be around for many years to come; therefore the owners of these existing power plants will most likely need to explore other options for reducing their emissions. Assuming a conservative 40-year useful power plant life, and looking only at the plants built through the 1990's, 667 of these units, representing more than 290 GW of capacity, will be operating into the next decade and beyond. Most (379) of these are coal-fired units; 243 are natural gas-fired, and 45 are oil-fired. The CO2 emissions contribution from these units alone is currently about 1.6 billion tons per year (roughly 62% of total U.S. electric utility sector emissions). A projection of future emissions from just these units over the next 40 years is shown by fuel type in Figure 2. The projection here assumes that each unit will be retired after operating for 40 years. If this projection were to hold true, these existing 667 power plants would collectively be responsible for emitting 30.2 billion tons of CO2 to the atmosphere over the remainder of their hypothetical lifetimes (26.7 billion tons from the coal units alone). 2,000

~

1,500

C

1,000 C

.2 500

0 2000

2005

2010

2015

2020

2025

2030

2035

2040

Figure 2:CO2 Emissions Projection for Units Built Between 1970 and 1999 (Assuming a Fixed 40-Year Operating Life)

This simplified analysis however does not tell the whole story. It does not include the emissions from units built prior to 1970, nor additional or replacement units that have already come on-line or will through 2040 (most of which will likely continue to employ conventional technology, rather than advanced power generation cycles that might be more amenable to CO2 emissions control). It also does not consider that many of these units will likely be able to produce economical power years beyond age 40. Assuming that a societal aspiration exists to begin addressing climate change within this decade, a strategy must be conceived to help these existing plants continue to produce affordable power while meeting their CO2 reduction requirements. Solutions beyond retiring this still valuable and productive stock or attempting to purchase increasingly expensive offsets must be developed to address these plants' large carbon liability, while maintaining their economic viability.

OPPORTUNITY FOR G E O L O G I C A L SEQUESTRATION The Battelle CO2-GIS currently contains information and spatial extents for some 117 geologic formations that could be amenable to CO2 disposal. These include current and prospective CO2 enhanced oil recovery operations, coal basins, and deep saline formations. Figure 3 is a map of the continental U.S. showing locations of the set of existing power generating units built since 1970 superimposed against these disposal reservoirs. Visual inspection reveals that many of these units lie directly above or in close proximity to possible disposal sites. However, it can also be seen that there are many generating units that are far from known CO2 disposal targets. Using the built-in analysis capability of the Battelle CO2-GIS, we are able to

1110 evaluate more thoroughly the opportunity that retrofit carbon capture and geologic sequestration offers this stock of plants.

Figure 3: U.S. Fossil-Fired Power Generating Units Built after 1970 and Major CO2 Geologic Disposal Reservoirs 2 Utilizing the basic spatial analysis capability of the system, we find that of the 379 coal plants built within this time frame, 244 lie directly above either a deep saline formation or a coal basin. Of the 216 such units that began operating in the 1970's, 146 sit atop a deep saline formation or coal seam and 5 are within 50 miles of an existing or prospective EOR field, representing over 70% of the annual emissions from this group of coal plants. In all, 66% of the total emissions from all 1970's vintage plants are within close proximity to potential disposal sites. For the 1980's plants, 61% of their emissions occur within a short distance to a disposal pathway, dropping to 47% for the 1990's plants' emissions. Deep saline formations are the reservoirs that underlie the most plants (44% of the total stock) across all vintage categories, reaching as high as 70% of all the 1980's natural gas fired plants. Coal seams are the next most prominent formation type located close to existing power plants, occurring beneath some 40% of 1970's vintage coal-fired plants. EOR fields offer the fewest options in close proximity to existing power plants, with only 18 of the 667 plants sitting within 50 miles of an existing or prospective EOR site. Overall, roughly 63% of the total emissions from these 667 units occur within close range of a possible disposal site, offering a promising opportunity for carbon capture and disposal. The CO2-GIS also contains an economic screening capability that seeks to optimize the matching of CO2 source and sink by assessing the costs of CO2 capture, transport, and disposal for each plant and reservoir combination. A previous paper [10] describes this functionality in greater detail. Expanding the assumed maximum search radius to 100-miles around each unit, we examine the available disposal pathways and identify those that appear most economical. Results of this analysis indicate that of the 667 units, 568 are located within 100 miles of at least one potential disposal reservoir. The results for each class of reservoir, 2Additional Legend for Figure 3: Dark solid areas represent major coal basins. Lightertextured areas represent deep saline formations. Blackdots indicate locationswhere CO2 injection for enhanced oil recoveryis on-going. The oil derrick symbol highlights areas with near-termprospects for CO2 enhanced oil recoveryprojects.

1111 including the number of plants selecting them for CO2 disposal and the average levelized cost per ton of CO2 captured, transported, and injected, are presented in Table 1. The majority of generating units elect to sell their C02 to "value added formations" which include enhanced oil recovery fields and deep coal seams, for which there would likely be an offsetting revenue stream from hydrocarbon recovery. Nevertheless, significant portions of the stock dispose of their CO2 in nearby deep saline formations. There is no direct revenue associated with this type of disposal, so the costs are much greater per ton of CO2 than for the "value added formations". Recalling that 294 of the total stock of plants sit directly over a deep saline formation, this results in many of these plants electing to build a much longer pipeline to sell their CO2 instead to a revenue-producing formation. This also suggests that many of the 176 plants that do opt to inject into a deep saline formation have no "value added" disposal options within the 100-mile radius. However, both the geographic distribution and storage capacity of deep saline formations is far greater than for enhanced oil recovery fields in particular, which could ultimately reduce the cost differences as the CO2 demand for EOR becomes saturated. While the value of methane produced from coal seams under CO2 injection is not as great as the oil produced from EOR operations, it does help to offset some of the capture and disposal costs. This, along with the broad geographic extent of the coal seams make this also a promising disposal option, accepting the majority of emissions from these units.

TABLE 1 RESULTSOF GENERATINGUNITCO2 DISPOSALECONOMICSELECTIONANALYSIS

# Units CO2, million tons/yr Req'd Pipeline, miles Av~. Cost S/ton 3

Enhanced Oil Recovery 62 120 4,500 1.50

Deep Coal Seams 330 950 19,800 18

Deep Saline Formations 176 250 11,600 61

In order to transport the C02 from source to sink, a network of pipelines will be required. Table 1 indicates the total pipeline length needed to deliver CO2 from each generating unit to its reservoir of choice. This figure assumes an average 15% adder to the straight-line distance to account for anticipated routing allowances. It also factors an additional 25 miles from the edge of a chosen coal basin or saline formation to locate an acceptable injection site. That said, these figures also assume that each generating unit builds a separate pipeline to its chosen disposal site. However, if capture and disposal of CO2 were developed on a scale such as envisioned here, a national network of interconnected CO2 pipelines would likely emerge with time. To illustrate the level of savings possible by evolving towards an interconnected national pipeline system, we note that many of the existing power plants in the U.S. have multiple generating units at the same site. By simply allowing a single pipeline to be shared by all the units at a particular location, the total required pipeline length needed to transport the emissions from existing power plants falls from over 35,000 miles to just over 18,000 miles. A more thoroughly coordinated system would reduce this further.

CONCLUSIONS

Is IGCC paired with carbon capture and disposal the power generation technology bridge to a transformed energy system? Perhaps, although it will likely be years before it is deployed at a wide scale. In the meantime, there are presently over 1,337 large conventional fossil-fired generating units across the United States that together emit some 2.3 billion tons of CO2 into the atmosphere each year. A large number of these plants are quite old and will likely be shut down and replaced with cleaner, more efficient plants (some 3The authors believe that the cost numbers presented in this table should be interpreted as relative indicators of the cost of capture and disposalrather than precise engineeringestimates.

1112 no doubt with IGCC), rather than be extensively upgraded or overhauled in the face of climate change and other environmental challenges. However, there are a significant number of units that have been built in the past few decades that have plenty of generating life remaining and will continue to operate into a future where carbon emissions are increasingly constrained. As far as U.S. electricity demand and climate change mitigation efforts are concerned, one cannot simply write off these plants' power production or resulting emissions; as we move forward and begin to define a sensible strategy for the level of emissions reduction required to help stabilize atmospheric concentrations of greenhouse gases, the continued operation and emissions from these units must be considered. Retrofitting these units with carbon capture systems and disposing of the CO2 in nearby geologic formations is an option that could help mitigate the large volumes of CO2 produced by these plants. Yet, this will not be an option for every unit. The 99 units producing 132 million tons of CO2 per year that cannot easily take advantage of geologic disposal would need to consider other options (including, but not limited to the purchase of CO2 offsets, repowering with advanced technology, or early retirement). For others, while geologic disposal options may exist, the cost of capture may prove prohibitively high (for small peaking natural gas turbines in particular). In such cases, other options will undoubtedly prove more economical and should be examined. Nevertheless, if we are serious about addressing our climate change mitigation obligations, carbon capture and geologic disposal should be considered in the portfolio of options.

REFERENCES

1. The United Nations Framework Convention on Climate Change. Article 2. http ://unfccc.int/resource/conv/conv_004.html (1992). 2. Wigley, T.M.L., Richels, R., & Edmonds, J. (1996) Economic and environmental choices in the stabilization of atmospheric CO2 concentrations. Nature, 379, 240-243. 3. Edmonds, J., J. Clarke, J. Dooley, S. H. Kim, S. J. Smith. 2002. "Stabilization of CO2 in a B2 World: Insights on The Roles of Carbon Capture and Disposal, Hydrogen, and Transportation Technologies," submitted to Energy Policy, Special Issue, J. Weyant and R. Tol (eds.). 4. Energy Information Administration. 2001. Emissions of Greenhouse Gases in the United States 2000. U.S. Department of Energy. DOE/EIA-0573(2000). 5. JJ Dooley, SH Kim and PJ Runci. "The Role of Carbon Capture, Sequestration and Emissions Trading in Achieving Short-Term Carbon Emissions Reductions." Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies. Sponsored by the IEA Greenhouse Gas R&D Programme. August 2000. 6. Dahowski, R., Dooley, J., Brown, D., Mizoguchi, A., and Shiozaki, M. "Understanding Carbon Sequestration Options in the United States: Capabilities of a Carbon Management Geographic Information System," Proceedings of the First National Conference on Carbon Sequestration. Washington, DC, May 2001. 7. Energy Information Administration. Annual Electric Generator Report -- Utility (2000). EIA-860A2000. April 8, 2002. 8. Energy Information Administration. Annual Electric Generator Report -- Nonutility (2000). EIA-860B2000. May 21, 2002. 9. JJ Dooley and RT Dahowski. ,"Examining Planned U.S. Power Plant Capacity Additions In The Context Of Climate Change" to be published in the proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies Sponsored by the IEA Greenhouse Gas R&D Programme (Kyoto, Japan October 2002). Pacific Northwest National Laboratory. PNNL-SA-36829. July 2002. 10. Dahowski, R., Dooley, J., Brown, D., and Stephan, A. "Economic Screening of Geologic Sequestration Options in the United States with a Carbon Management Geographic Information System," Proceedings of the Eighteenth Annual International Pittsburgh Coal Conference. Newcastle, NSW, Australia, December 2001.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1113

E X A M I N I N G P L A N N E D U.S. P O W E R PLANT C A P A C I T Y A D D I T I O N S IN THE C O N T E X T OF C L I M A T E C H A N G E JJ Dooley I and RT Dahowski 2 1 Battelle- Pacific Northwest National Laboratory 8400 Baltimore Avenue, Suite 201 College Park, Maryland 20740 z Battelle- Pacific Northwest National Laboratory P.O. Box 999 / Mail Stop K6-10, Richland, WA 99352

ABSTRACT This paper seeks to assess the degree to which the 471 planned fossil fueled power plants announced to be built within the next decade in the continental U.S. are amenable to significant carbon dioxide emissions mitigation via carbon dioxide capture and disposal in geologic reservoirs. In particular, we seek to assess the looming "carbon liability" (i.e., the potential 1 billion tons of annual CO2 emissions) that these power plants represent for their owners and for the nation as the U.S. begins to address climate change. The combined generating capacity of these 471 planned plants is 320 GW. Less than half of these plants are located in the immediate vicinity of potentially suitable geologic carbon dioxide disposal reservoirs. The authors examine two hypothetical scenarios for how these plants will access known CO2 disposal reservoirs.

INTRODUCTION The United States Senate ratified the United Nations Framework Convention on Climate Change (UNFCCC) on October 15, 1992 [ 1]. Since then there have been numerous legislative proposals introduced in the United States Congress suggesting various mechanisms for controlling U.S. emissions of greenhouse gases, with most of these proposals focusing on reducing greenhouse gas emissions from large point sources such as fossil fired power plants. The current U.S. Presidential Administration has reaffirmed the U.S. commitment to achieving the stated goal of the UNFCCC, which calls for the "stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system"[2]. Numerous modeling efforts strongly suggest that fulfilling this stabilization goal will require a profound transformation of the global energy system, and of particular relevance for the present analysis, will require the very large scale deployment of advanced emission mitigation technologies such as carbon capture and disposal before the middle of this century (see for example [3]). Therefore, given average power plant lifetimes that are likely more than 40 years for new plants, new additions to a nation's power plant infrastructure represent early opportunities for the introduction of new emissions mitigation technologies such as carbon capture and disposal. However, if these new power

1114 plants are unable to use carbon capture and disposal options, they instead likely represent a growing financial liability for their owners and operators as the U.S. begins to reduce its emissions of greenhouse gases. This paper seeks to assess the degree to which the 471 planned 1 fossil fired power plants announced to be built within the next decade in the continental U.S. are amenable to significant carbon dioxide emissions mitigation via carbon dioxide capture and disposal in geologic reservoirs.

B A T T E L L E CO2-GIS The Battelle CO2-GIS is a geographic information system (GIS) based model for CO2 source and sink data. At this time, it contains data (e.g., fuel type, location, vintage, ownership, rated capacity) on all fossil-fired generation capacity in the United States and Canada with a rated capacity of at least 100 MW. This represents 1,337 units with a rated capacity of 453 GW and annual CO2 emissions in excess of 2.27 billion tons. The Battelle CO2-GIS also contains key data on potential geologic reservoirs that could possibly be used for CO2 disposal. This includes data on current and prospective CO2 enhanced oil recovery (EOR) projects as well as on priority deep saline formations and coal basins with potential for CO2 disposal. In all, there are some 117 possible reservoirs currently represented in the model. The most recent version of the Battelle CO2-GIS is described elsewhere [4].

PLANNED FOSSIL P O W E R PLANT ADDITIONS F O R THE C O N T I N E N T A L U.S. For the present analysis, we have augmented the data already contained in the Battelle CO2GIS model with information on 471 power plants announced to become operational between June 2002 and the end of calendar year 2010. Each of these plants has a planned rated capacity of at least 100MW. Data for these planned power plants come from a number of different data sources [5, 6, 7, 8]. Figure 1 shows the geographic location of these planned power plants and the major CO2 disposal reservoirs identified to date and contained within the Battelle CO2-GIS. Natural gas fired turbines dominate these 471 power plants. More than 80% (396 out of 471) of these fossil fired plants are natural gas fired, thus continuing a decades' old trend in the U.S. of increasing reliance on natural gas as the fuel of choice for new power plants. The remaining plants are coal fired. Nine of these coal plants are designed to make use of integrated gasification combined cycle (IGCC) power plant concepts. The remaining 67 coal fired plants will make use of more conventional coal-fired power cycles. There are no oil-fired plants scheduled to come on line that exceed the 100MW capacity threshold being used in this analysis.

t It is important to acknowledge that these power plants represent announced plans to build a power plant at a given site. There is no guarantee that all of these plants will actuallybe built.

1115

•

i ¸

,

Ranned Capacity #r

Coal Ga

@ 200"2.Ba,~el!eMemorial in~Hut~

Figure 1: Planned Fossil-Fired Power Plant Additions in the U.S. and Major CO2 Geologic Disposal Reservoirs 2 These 471 power plants represent a planned addition of 320 G W over the coming decade. This would represent a nearly 50% increase with respect to the total fossil fired capacity already installed in the continental U.S. These planned plants themselves have the potential to release 1.01 billion tons of CO2 to the atmosphere annually 3. Moreover if one conservatively assumes that these power plants will have operating lifetimes of 40 years, then this set of new power plants alone is theoretically capable of generating 40.1 billion tons o f CO2 (or 11.0 billion tons of carbon) to the atmosphere over their hypothetical lifetimes. That is almost twice the current global annual emissions of carbon from all sources.

P R O X I M I T Y T O G E O L O G I C A L CO2 D I S P O S A L R E S E R V O I R S Given the potential "CO2 emissions shadow" cast by these plants over the course of their lifetimes, we wanted to explore the potential for reducing emissions by these plants through the use of carbon capture and disposal technology. The first level of analysis would be to assess the extent to which these plants happen to lie near reservoirs with promise for CO2 disposal.

2 Legend for Figure 1. Light stars represent planned natural gas fired power plant additions. Black stars represent planned coal fired capacity additions. Textured gray areas are deep saline formations believed to be suitable for CO2 disposal. Solid dark gray areas represent deep coal seams believed to be suitable for CO2 disposal. Black dots represent locations that are currently using CO2 for enhanced oil recovery while the oil derrick symbols represent prospective areas for near term CO2 driven enhanced oil recovery. 3 This paper's calculations of these yet-to-be-built power plants' generating capacity and resulting CO2 emissions are based upon a number of key assumptions. Foremost, is an assumed average capacity factor of 65% for all of these plants whether they be coal fired, IGCC plants or natural gas turbines. According to data contained in the Battelle CO2-GIS, the installed power plants in the U.S. have an aggregate average capacity factor of 51.5%, so the assumption of 65% capacity factor would be a substantial improvement in terms of reliability with respect to the current installed capacity.

1116 Table 1 describes how these planned power plants line up with potential CO2 disposal reservoirs. TABLE 1 PLANNEDU.S. POWERPLANTS& THEIRPROXIMITYTO POTENTIALCO2 DISPOSALRESERVOIRS

NGCC Conventional Coal IGCC

Total Number of Units By Fuel Type 396 66

Units Directly Above Deep Saline Formations 127 36

Units Directly Above ValueAdded Formations 58 24

Units within 25 miles of any reservoir 232 58

Units not within 50 miles of any reservoir 122 6

9

3

0

7

2

The 130 planned power plants that do not lie within 50 miles of any known geologic CO2 disposal reservoirs account for 29% of these power plants' annual emissions. This represents 296 million tons of CO2 that cannot be stored in these geologic reservoirs without building extensive pipeline networks. Assuming that at some point in the future plant operators will be charged for carbon emissions, this amount of uncaptured emissions is a fairly large financial liability for the owners of this long-lived capital stock. Table 1 also suggests that there are 82 planned power plants that lie directly above "value added formations. ''4 For the purposes of the present analysis, "value added formations" are defined as areas currently using CO2 for enhanced oil recovery (EOR), prospective near-term CO2-driven EOR formations, and deep coal seams believed to be suitable for CO2 disposal. These 82 power plants that sit adjacentto these potential "value added formations" are capable of generating 217 million tons of CO2 per year. This is nearly an order of magnitude greater than current U.S. use of CO2 for EOR [9]. Furthermore given that most EOR field operations typically last only 5-30 years [ 10], can these long-lived power plants count on selling their CO2 to these "value-added" applications year-after-year? There could well me too much CO2 trying to find a productive use even from this small subset of plants. If supply does indeed exceed demand by a significant fraction, then the price buyers would be willing to pay for CO2 for these value added applications should decline rapidly, perhaps even approaching zero. Note also that there are no IGCC plants in close proximity to any known EOR or ECBM prospects. Lastly, before leaving this basic spatial analysis of CO2 sources (planned power plants) and sinks (these potential geologic reservoirs for CO2), we wish to examine the role potentially played by deep saline formations. Fully 35% of all of these announced power plants (166) sit directly above identified deep saline formations. Moreover 53% of all of these planned plants (250), accounting for 51% of all of their emissions, sit within 25 miles of a potential deep saline formation CO2 disposal pathway. No other class of geologic reservoirs has the potential to meaningfully address these planned power plants' emissions over the course of their lifetimes without building lengthy CO2 pipelines.

4 For the purposes of this analysis, "directly above value added formations" connotes different things for the different classes of geologic reservoirs. Because of the spatial resolutionof the data within the Battelle CO2-GIS,a plant is determined to be above an EOR field if within 25 miles of the point representing the field. For coal beds, where we have better spatial coveragea plant must sit directlyabove them.

1117

DEPLOYMENT SCENARIOS We next turn our attention to a more sophisticated analysis where we attempt to examine how the various CO2 disposal reservoirs in the U.S. might be used under differing economic and regulatory environments. In order to perform this analysis, we will employ the economic screening function built into the Battelle CO2-GIS which seeks to optimize the matching of CO2 source and sink by assessing costs for CO2 capture, transport and disposal, s The first case we examine here is a hypothetical scenario in which each power plant is allowed to build up to a 100 mile pipeline in an attempt to find the most productive use for its CO2. That is, each plant is asked to minimize its cost subject to only one constraint; it cannot build a pipeline longer than 100 miles. This case results in 36 of these power plants attempting to sell 77.3 million tons o f CO2 annually to EOR markets while an additional 215 plants attempt to sell their annual production of 480.2 million tons of CO2 for ECBM production. Lastly, 157 plants annually seek to dispose of their 287.5 million tons of CO2 into deep saline formations. This supposedly economic efficient case comes at the potential cost o f creating a massive U.S. CO2 pipeline network stretching some 13,000 miles of straight-line pipe. If instead of assuming that each source and sink combination can be effortlessly sited along straight line pipes, one assumes less optimal pipeline routes and the need for additional pipeline to locate suitable injection points into large reservoirs, the total national CO2 infrastructure from these new plants climbs to 25,700 miles. 6 The second case revolves around a purely hypothetical regulation that limits CO2 disposal to the nearest formation with no power plant allowed to build a pipeline o f more than 25 miles. This case results in only 8 of these new power plants attempting to sell 16.0 million tons of CO2 to EOR markets annually while an additional 99 plants attempt to sell their annual production of 260.1 million tons of CO2 for ECBM production. Lastly, 182 plants seek to use deep saline formations as the ultimate disposal point for their annual 347.8 million tons of CO2. This "regulatory-oriented" scenario creates a national pipeline infrastructure of only 1200 miles o f straight-line pipeline or 9500 miles of pipeline under the more realistic assumptions noted above.

CONCLUSIONS While it is unclear exactly how many of the 471 fossil fired power plants examined here will actually end up being brought on line, it is clear that many of these plants are not ideally situated to avail themselves of carbon capture and disposal technologies. This implies that the owners of many of these power plants will need to either invest in massive COz pipeline networks, consider paying others for increasingly costly emissions offsets, or prematurely s The cost function computes a total levelized cost for any source/sink combination by applying a series of cost factors for the three major aspects of CO2 capture and disposal: (1) CO2 capture (e.g., post combustion capture from a dilute flue gas stream is more expensive than COz derived from a high purity CO2 stream such as an IGCC), (2) CO2 transport (i.e., a cost per mile of pipeline constructed is assessed) and (3) CO2 disposal (i.e., net cost for CO2 disposal in a deep saline formation is more expensive than CO2 disposed of in a coal seam for enhanced coal bed methane production while CO2 used in EOR is the cheapest disposal route). 6 In this perhaps more realistic pipeline scenario we assume, that all straight line pipeline distances have to carry a 15% adder to account for pipeline siting around obstacles and all deep saline and ECBM applications require an average 25 miles of additional pipeline to penetrate the perimeter of the large reservoirs and locate a suitable injection site.

1118 retire these new plants. None of these offer a particularly attractive option. A failure to take into account emissions mitigation options raises the cost of complying with the U.S.'s obligations under the UNFCCC and likely passes a heavy burden on to future generations. A failure to do so also increases potential out year liabilities for the owners of these plants and their shareholders. Under any scenario, the U.S. will need a portfolio of proven geologic CO2 disposal reservoirs. Placing too much emphasis on "value added formations" will needlessly strand a tremendous amount of fossil fired power plants. Consideration should also be given now to what kind of a regulatory framework will guide the evolution of a national CO2 pipeline infrastructure. If this pipeline infrastructure issue is not considered proactively, the U.S. might end up with a massive and publicly unacceptable CO2 pipeline network that will itself hamper the successful wide scale adoption of capture and disposal technologies that it is meant to support.

REFERENCES

1. United Nations Framework Convention on Climate Change: Status of Ratification. 2001. Updated: December 11, 2001. http://unfccc.int/resource/conv/ratlist.pdf 2. The United Nations Framework Convention on Climate Change. Article 2. http ://unfccc.int/resource/conv/conv_004.html (1992). 3. Dooley, JJ, Kim, SH, and Runci, PJ. "The Role of Carbon Capture, Sequestration and Emissions Trading in Achieving Short-Term Carbon Emissions Reductions." Proceedings of the Fitth International Conference on Greenhouse Gas Control Technologies. Sponsored by the IEA Greenhouse Gas R&D Programme. August 2000. 4. Dahowski, R., Dooley, J., Brown, D., Mizoguchi, A., and Shiozaki, M. "Understanding Carbon Sequestration Options in the United States: Capabilities of a Carbon Management Geographic Information System," Proceedings of the First National Conference on Carbon Sequestration. Washington, DC, May 2001. 5. Electric Power Supply Association. 2002. Announced Merchant Plants. Prepared July 1, 2002. Online database of additions to merchant power plants, http://www.epsa.org/ 6. Energy Information Administration 2000. Existing Capacity and Planned Capacity Additions at U.S. Electric Utilities by Energy Source, Table 1. U.S. Department of Energy. http ://www. eia.doe, gov/cneaf/electricity/ipp/html 1/t 1p01 .html 7. Energy Info Source. 2002. New Plant Construction. Last updated July 9, 2002. http ://www.energyinfosource.com 8. Klara, Scott and Shuster, Erik. 2002. "Tracking New Coal-Fired Plants: Coal's Resurgence in Electric Power Generation." (http://www.netl.doe.gov/coalpower/oces/pubs/ncp5-2802.PDF). U.S. Department of Energy, National Energy Technology Laboratory. May 28, 2002. 9. Stevens, SH, Kuuskraa, VA, and Gale, J. "Sequestration of CO2 in Depleted Oil and Gas Fields: Global Capacity, Costs, and Barriers." Proceedings of the FitCh International Conference on Greenhouse Gas Control Technologies. Sponsored by the IEA Greenhouse Gas R&D Programme. August 2000. 10. Stevens, SH, Kuuskraa, VA, and Taber, JJ. "Sequestration of CO2 in Depleted Oil and Gas Fields: Barriers to Overcome in the Implementation of CO2 Capture and Storage (Dissued Oil and Gas Fields." lEA Greenhouse Gas R&D Programme Report No. PH3/22. February 2000.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1119

UNCERTAINTIES IN CO2 CAPTURE AND SEQUESTRATION COSTS E.S. Rubin and A.B. Rao Department of Engineering and Public Policy Carnegie Mellon University Pittsburgh, PA 15213 ABSTRACT The cost of CO2 avoidance depends on a wide variety of factors and assumptions whose impacts have not been fully considered in past assessments of carbon capture and sequestration technologies. As part of the USDOE's Carbon Sequestration Program, we have developed an integrated modeling framework to evaluate the performance and costs of alternative CO2 capture and sequestration technologies for fossil-fueled power plants, in the context of multi-pollutant control requirements. This model (called the IECM-CS) allows for explicit characterization of the uncertainty or variability in any or all model input parameters. This paper reviews the major sources of uncertainty or variability in CO2 cost estimates, then uses the IECM-CS to analyze uncertainties in CO2 mitigation costs for currently available (amine-based) COR capture technologies applicable to coal-fired power plants. INTRODUCTION Development of improved technology to capture and sequester the CO2 emitted by power plants using fossil fuels m especially coal m is the subject of major research efforts worldwide. The attraction of this option is that it would allow abundant world resources of fossil fuels to be used for power generation and other applications without contributing significantly to atmospheric emissions of greenhouse gases. The two key barriers to carbon capture and sequestration (CCS), however, are the high cost of current CO2 capture technologies, and uncertainties regarding the technical, economic and political feasibility of CO2 storage options. Assuming geological storage of CO2 indeed proves to be viable, how much would it likely cost to capture and store the CO2 from a new coal-fired power plant? Various studies have addressed this question [ 1-7], but each study typically employs different assumptions that produce different results. Herzog (1999) and others have summarized recent cost studies and sought to adjust their results to a more consistent basis [8, 9]. Nonetheless there still remains substantial confusion and lack of understanding in both the technical and policy communities about the magnitude of CCS costs and the factors that affect it. FACTORS AFFECTING CCS COST In this paper we attempt to peel back some of the cobwebs that continue to obfuscate answers to what many believe is the simple question of how much it costs to capture and sequester CO2 emissions from power plants. We use the term "uncertainties" very loosely in this paper to describe the many different factors that contribute to differences in reported cost results for CCS systems. We begin with a brief review of the key determinants of CO2 control cost.

Defining the System Boundary: The first requirement is to clearly define the "system" whose CO2 emissions and cost are being characterized. The most common assumption in economic studies is a single power plant that captures CO2 and transports it to an off-site storage area such as a geologic formation. The CO2 emissions not captured are released at the power plant stack along with other pollutants. Other system boundaries that are sometimes used (or implied) in reporting CO2 abatement costs may include CO2 emissions over the complete fuel cycle that includes the extraction, refining and transportation of coal or other fuels used for power generation, as well as any emissions from byproduct use or disposal. Emissions of other greenhouse gases (expressed as equivalent CO2) also

1120

are included in some analyses. Still larger systems might include all power plants in a utility company's system; all plants in a regional or national grid; or a national economy where power plant emissions are but one element of the overall energy system being modeled. In each of these cases it is possible to derive a mitigation cost for CO2 but the results are not directly comparable because they reflect different system boundaries and considerations.

Defining the Technology and Time Frame: Costs will vary with the choice of CCS technology and the power system that generates CO2 in the first place. What is often less clear in economic evaluations is the nature and basis of assumptions about the future cost of a technology, particularly "advanced" technologies that are still under development or not yet commercial. Such cost estimates frequently reflect assumptions about the "n th plant" to be built sometime in the future when the technology is mature. Other estimates may reflect the expected benefits of technological learning. The choice of time frame and assumed rate of cost improvements can make a big difference in CCS cost estimates.

Different Measures of Cost: Several different measures of cost are used to characterize CCS systems, but because many of these have the same units (e.g., dollars per tonne of CO2) there is great potential for misuse or misunderstanding. Perhaps the most widely used measure is the "cost of CO/ avoided," defined as: Cost of COz Avoided = [(COE)camre - (COE)ref] / [(CO2/kWh)ref - (CO2/kWh)capture] This value reflects the average cost (S/ton) of reducing atmospheric CO2 emissions by one unit of mass (nominally one ton), while still providing one unit of electricity to consumers (nominally one kWh). The choice of both the capture plant and the reference plant without CO2 capture and storage thus plays a key role in determining the CO2 avoidance cost. Usually (but not always) the reference plant is assumed to be a single unit the same type and size as the plant with CO2 capture. If there are significant economies of scale in power plant construction costs, differences in power plant size also can affect the cost of CO2 avoided. A measure having the same units as avoided cost can be defined as the difference in net present value of projects with and without CCS, divided by the difference in their CO2 mass emissions. However, unless the two projects produce the same net electrical output, the resulting cost per tonne is not the cost of CO/avoided; rather, we call it the "cost of CO2 abated." Numerically, this value can be quite different from the cost of CO2 avoided for the same two facilities. Arguably, it is the cost of electricity (COE) for plants with CO2 capture that is most relevant for economic, technical and policy analyses. It can be calculated as: COE = [(TCR)(FCF) + (FOM)]/[(CF)(8760)(kW)] + VOM + (HR)(FC) where, COE = cost of electricity (S/kWh), TCR = total capital requirement ($), FCF = fixed charge factor (fraction/yr), FOM = fixed operating costs ($/yr), VOM = variable operating costs (S/kWh), HR = net plant heat rate (kJ/kWh), FC = fuel cost ($/kJ), CF = capacity factor (fraction), 8760 = hrs/yr, and kW = net plant power (kW). Thus, many factors affect the COE, and hence the cost of CO2 avoided.

Unreported Assumptions: For a variety of reasons, cost studies do not always report all of the key assumptions that affect the cost of CO2 control. For example, the total capital requirement (TCR) includes the cost of purchasing and installing all plant equipment, plus a number of "indirect" costs that typically are estimated as percentages of total plant cost (TPC) [10]. Assumptions about such factors (such as contingency costs) can have a pronounced effect on cost results. Further, some CO2 cost studies exclude certain items (like interest during construction and other "owner's costs") when reporting total capital cost and COE. The term "total plant cost" doesn't always mean what it seems! The addition of a carbon capture and storage (CCS) system increases a plant's capital and operating costs, while lowering the net power output because of auxiliary energy requirements. The result is a higher COE relative to the identical plant without CO2 capture. The capacity factor of the capture plant is typically assumed to be the same as the reference plant, although some studies suggest that CCS plants may be utilized more extensively than an equivalent plant without COz capture [11]. Thus, the COE and the cost of CO2 avoided are both influenced by many factors that are not directly related to the design or cost of a CO2 capture and storage system (see Table 1). Unless such assumptions are transparent, results can be easily misunderstood.

1121

TABLE 1 TEN WAYS TO REDUCE CO2 CONTROL COSTS WITHOUT EVEN CONSIDERING THE COST OF CO2 CAPTURE 10. 9. 8. 7. 6. 5. 4. 3. 2. 1.

Assume high power plant efficiency Assume high-quality coal properties Assume low fuel costs Assume EOR credits for CO2 disposal Omit certain capital costs State results in short tons Assume a long plant lifetime Assume a low interest rate (discount rate) Assume high plant utilization (capacity factor) Assume all of the above!

QUANTIFYING COST UNCERTAINTIES

As noted earlier, we use the term "uncertainty" loosely to reflect the combination o f imprecise knowledge o f a parameter value, as well as the variability in parameter assumptions used for cost estimates. To quantify the impact of these factors, we use a computer model (called IECM-CS) developed for the U.S. Department o f Energy [ 12, 13]. The I E C M - C S estimates the performance and cost of a user-specified power plant configuration that may include a variety o f emission control technologies for regulated air pollutants (SO2, NOx, particulates and mercury) in addition to CO2 capture. The model also includes an amine scrubber system for CO2 capture at a pulverized coal plant. Models o f a natural gas combined cycle (NGCC) system and an integrated coal gasification combined cycle (IGCC) system with and without CO2 capture will soon be added. In each case the CCS system includes the costs of CO2 pipeline transport plus storage in a geologic reservoir (including options for enhanced oil recovery or enhanced coalbed methane recovery), or ocean disposal. A unique feature o f the IECM-CS is its ability to represent any or all input parameters as probability distribution functions rather than discrete (deterministic) values. The probabilistic results then reflect the interactions among all uncertain input variables. TABLE 2 DESIGN PARAMETERS FOR CASE STUDY OF NEW PULVERIZED COAL PLANT

Parameter Gross plant size (MW) Gross plant heat rate (U/kWh) Plant capacity factor (%) Coal characteristics Coal HHV (kJ/kg) %S %C Mine-mouth cost ($/tonne) Delivered cost ($/tonne)

]Value 500 9600 a 75 b Low-S 19,346 0.48 47.85 13.73 23.19 c

High-S 25,300 3.25 61.2 32.24 41.3¢

I

Parameter Emission standards NOx controls Particulate control SO2 control CO2 control CO2 capture efficiency (%) CO2 product pressure (kPa) Distance to storage (km) Cost year basis (constant $) Fixed charge factor

]

Value 2000 NSPS a LNB e +SCR t ESP g FGD h MEAi 90 13,790 i 165 2000 0.15 k

aNominal case is a sub-critical unit. Uncertaintycase includes supercritical unit. The uncertaintydistributions used are: Unc = Chance distribution (8968(p=0.5), 9600(p-0.5)); bUnc = Triangular(65,75,85); CUnc-- Triangular(l5.94,23.19,26.81); dNOx= 65 ng/J, PM = 13 ng/J, SO2 = 70% removal (upgraded to 99% with MEA systems); ~LNB= Low- NOx Burner; 'SCR = Selective Catalytic Reduction; gESP = Electrostatic Precipitator; hFGD= Flue Gas Desulfurization; iMEA= Monoethanolamine system;JSee Table 3 for uncertainty. kCorresponds to a 30-year plant lifetime with a 14.8% real interest rate (or, a 20-year life with 13.9% interest); Unc = Uniform(0.10,0.20) 1Unc= Triangular (35.31,41.97, 51.96)

Case Study of a New PC Plant: To illustrate the effect of uncertainties on CO2 control cost for one technology we present a case study o f a new pulverized coal (PC) power plant with an amine (MEAbased) CO2 capture system representing current commercial technology.

1122 TABLE 3 AMINE SYSTEM PERFORMANCEMODEL PARAMETERS

Performance Parameter

I

Units

CO2 removal efficiency % SO2 removal efficiency % NO2 removal efficiency % HC1 removal efficiency % Particulate removal eff. % MEA concentration wt% Lean solvent CO2 loading mol CO2/mol MEA Nominal MEA make-up . kg MEA/tonne CO2 MEA loss (802) mol MEA/mol SO2 MEA loss (NO2) mol MEA/mol NO2 MEA loss (HC1) mol MEA/mol HC1 MEA loss (exhaust gas) ppm NH 3 generation molNH3/molMEA ox Caustic for MEA reclaimer kg NaOH/tonneCO2 Cooling water makeup M3/tonne CO2 Solvent pumping head kPa Pump efficiency % Gas-phase pressure drop kPa Fan efficiency % Equiv. elec. requirement % regeneration heat CO2 product purity wt% CO2 product pressure MPa Compressor efficiency %

Data INominal (Range) ] Value Mostly 90 Almost 100 20-30 90-95 50 15-50 0.15-0.30 0.5-3.1 2 2 1 1-4 1 0.13 0.5-1.8 35-250 70-80 14-30 70-80 9-19 99-99.8 6.9-15.16 75-85

90 99.5 25 95 50 30 0.22 1.5 2 2 1 2 1 0.13 0.8 207 75 26 75 14a 99.5 13.79 80

i

Unc. Representation (Distribution Function) Uniform (85, 95) Uniform (99,100) Uniform (20,30) Uniform (90,95) Uniform (40,60) Uniform (20,30) Triangular (0.17,0.22,0.25) Triangular (0.5,1.5,3.1)

Uniform ( 1,4)

Triangular (0.5,0.8,1.8) Triangular (150,207,250) Uniform (70,80) Triangular (14,26,30) Uniform (70,80) Uniform (9,19) Uniform (99,99.8) Triangular (6.9,13.79,15.16) Uniform (75,85)

TABLE 4 M E A COST MODEL PARAMETERS

Capital Cost Elements

~om. Value*

Process area cosis (9 areas) a Total process facilities cost PFC b Engineering and home office 7 % PFC c General facilities 10 % PFC d Project contingency 15 % PFC e Process contingency 5 % PFC f Total plant cost (TPC) = sum of above Interest during construction calculated Royalty fees 0.5 % PFC g 1 month h Pre-production costs VOM & FOM Inventory (startup) cost 0.5 % TPC ~ Total capital reqmt (TCR) = sum of above

O&M Cost Elements ]

Nom. Value*

Fixed O&M Costs 0FOM) Total maintenance cost 2.5 % TPCj Maintenance cost 40 % of total maint. allocated to labor cost Admin. & support labor 30 % of total labor Operating labor 2 jobs/shiR k

Variable O&M Costs (VOM) Reagent (MEA) cost Water cost CO2 transport cost CO2 storage/disposal cost Solid waste disposal cost

$1250/tonne MEA I $0.2/m 3 $0.02/tonne CO2/K1TI

TM

$5/tonne CO2" $175/tonne waste b

*Uncertainty distributions are given below, aTheindividual process areas modeled are: flue gas blower, absorber, regenerator, solvent processing area, MEA reclaimer, steam extractor, heat exchanger, pumps, CO2 compressor. The sum of these is the total process facilities cost (PFC). The uncertainty distributions used are: bNormal(1.0,0.1), CTriangular(5,7,15), dTriangular(5,10,15) CTriangular(10 15 20) f, Triangular (2,5,10), g Triangular (0,0.5,0.5), hTriangular (0.5,1,1), q'riangular (0.4,0.5,0.6), jTriangular' (1 2.5 5) k Tri'a~gular (1,2,3))Uniform (1100,1300), "Triangular (0.004,0.02,0.06), "Chance distribution (-10(p-0.25), -5(p=0.25), 3(p=0'.05), 5(p=0.35), 8(p=0.l)) Table 2 lists the key power plant parameters and assumed uncertainty distributions, while Tables 3 and 4 show the performance and cost parameters, respectively, for the CO2 capture and storage system. The nominal case assumes geologic storage of CO2 at a net cost to the plant owner, while the uncertainty (variability) case includes the sale o f CO2 for enhanced oil recovery (EOR).

1123 TABLE 5 PROBABILISTICCOSTRESULTSFORCO2 CAPTUREPLANTS Case Low-S coal Reference plant C02 capture plant: unc. in both ref & capture plant unc. in capture plant only Hi2h-S coal Reference plant capture plant: unc. in both ref &.capture plant unc. in capture plant only C O

Mean

COE ($/MWh) Median Range

Avoidance Cost ($/tonne CO2 av.) Mean Median Range . . . . . . . . . . . . . . . . . . . . . . . . . . .

. ....

,:

:

.

.

.

.

48.0

48.0

36-63

: :i:: :1 :~: : :i

iii :

89.5 89.5

98.1 98.1

54-132 54-132

53.0 49.5

21-91 6-102

55.3

55.0

43-69

96.3 96.3

95.9 95.9

63-138 63-138

:,,:

53.3 48.8 :

.

.

:I

:....

2

55.8 52.2

56.3 51.7

23-90 9-106

Figure 1 shows the cumulative distribution function (cdf) for the cost of CO2 avoided. One curve reflects only the uncertainty and variability in the parameters of the CO2 capture and storage system. A second curve adds uncertainty and variability in four key power plant parameters that also influence the COE and avoided cost. We consider cases where these parameter values are identical for the reference and capture plants, and another case where they differ. Table 5 summarizes the mean, median, and range of the overall distributions for COE and cost of CO2 avoided for several cases. The mean and median values of the cost of COz avoided lie in the range of roughly $49 to $56/tonne CO2. When uncertainty and variability assumptions are taken into account the range widens considerably. With uncertainties only in the CCS system, the 95% probability interval varies by approximately a factor of three, from $32 to $75/tonne COz. The most significant variables here were the CO2 capture efficiency, lean solvent CO2 loading of the amine system (which determines the regeneration heat requirements), the efficiency of heat integration (in terms of net power loss), and the CO2 storage/disposal cost. Adding variability in plant parameters has a measurable effect on COE, but a small impact on avoidance cost if the reference plant and capture plant employ the same assumptions. Otherwise the impact on avoidance cost can be large, as illustrated in Table 5. Results for the two different coal types show that fuel choice assumptions also can have a large effect on COE but a much smaller effect on avoided cost relative to the same plant without CCS. CONCLUSIONS

The analysis method used in this paper can be readily applied to other types of power generation and CCS systems, which will be part of our on-going work. While this study did not attempt to quantify the effects of technology innovation and learning on future cost reductions, this is nonetheless an important factor that is being considered in other research [ 14]. In the context of long-term scenarios or projections, assumptions about rates of technical are critical to cost estimates for CO2 capture and storage. ACKNOWLEDGEMENTS This research was supported by the U.S. Department of Energy's National Energy Technology Laboratory (Contract No. DE-FC26-00NT40935), and by the Center for Integrated Study of the Human Dimensions of Global Change through a cooperative agreement between the National Science Foundation (SBR-9521914) and Carnegie Mellon University. The authors alone, however, are responsible for the content of this paper.

1124 1.o .......................................................................................~

...........

0.8

--~ 0.7

0

10

20

30

40

51)

60

70

80

90

q00

Avoidance Cost ($/tonne C02 avoldod)

Figure 1: Effects of parameter uncertainty and variability on the cost of CO2 avoided. The dotted lines at the top and bottom of the graph encompass the 95% probability interval.

REFERENCES

1. Smelser, S.C., Stock, R.M. and G.J. McCleary (1991). "Engineering and economic evaluation of CO2 removal from fossil-fuel-fired power plants", EPRI IE-7365, Vol. 2, Palo Alto, CA. 2. Riemer, P., Audus, H. and A. Smith (1993). "Carbon dioxide capture from power stations", IEA Greenhouse Gas R&D Programme, Cheltenham, United Kingdom. 3. Hendriks, C. (1994). Carbon Dioxide Removal from Coal-fired Power Plants, 14-223, Kluwer Academic Publishers, The Netherlands. 4. Leci, C.L. (1996). "Financial implications on power generation costs resulting from the parasitic effect of CO2 capture using liquid scrubbing technology from power station flue gases", Energy Convers. Mgmnt, 37(6-8), 915-921. 5. Chapel, D., Ernst, J. and C. Mariz (1999). "Recovery of CO2 from flue gases: Commercial trends", Proc. of Canadian Society of Chemical Engineers Annual Meeting, 4-6 October, 1999, Saskatoon, Saskatchewan, Canada. 6. Simbeck, D. (1999). "A portfolio selection approach for power plant CO2 capture, separation and R&D options", Proc. of 4 th International Conference on Greenhouse Gas Control Technologies, Elsevier Science Ltd. 7. Rao, A.B. and Rubin, E.S. (2002). "A Technical, Economic and Environmental Assessment of Amine-based Carbon Capture Technology for Power Plant Greenhouse Gas Control," Environ. Sci. Technol. 36(20), 4467-4475. 8. Herzog, H.J. (1999). "The economics of CO2 capture", Proc. of 4 th International Conference on Greenhouse Gas Control Technologies, Elsevier Science Ltd. 9. Jeremy D. (2000). Economic Evaluation of Leading Technology Options for Sequestration of Carbon Dioxide, M.S. Thesis, MIT, Cambridge, MA. 10. TAG (1993). Technical Assessment Guide, EPRI TR 102276, EPRI, Palo Alto, CA. 11. Johnson, T.L. (2002). Electricity Without Carbon Dioxide: Assessing the Role of Carbon Capture and Sequestration in U.S. Electric Markets, Ph.D. Thesis, Carnegie Mellon University, Pittsburgh, PA. 12. Rubin, E.S., Kalagnanam, J.R., Frey, H.C. and M.B. Berkenpas (1997). "Integrated Environmental Control Modeling of Coal-Fired Power Systems", J. Air & Waste Mgmt. Assoc., 47, 1180-1188. 13. IECM (2001). Integrated Environmental Control Model User Documentation, www.iecmonline.com Center for Energy and Environmental Studies, Carnegie Mellon University, Pittsburgh, PA. 14. Rubin, E.S., Taylor M.R., Yeh S. and D.A. Hounshell (2002). "Experience Curves for Environmental Technology and Their Relationship to Government Actions," Proc. of GHGT-6 Sixth International Conference on Greenhouse Gas Control Technologies, October 1-4, 2002, Kyoto, Japan.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1125

COSTS OF RENEWABLE ENERGY AND CO2 CAPTURE AND STORAGE John Davison IEA Greenhouse Gas R&D Programme, Cheltenham, GL52 7RZ, UK

ABSTRACT This paper compares the costs and emissions of renewable energy technologies (wind, solar and biomass) and electricity generation from fossil fuels with capture and storage of CO2. Where natural gas is available at low costs, gas-fired combined cycle plants with capture and storage of CO2 have the lowest electricity generating costs. If the cost of gas is high, wind turbines at favourable sites are cheaper. The cost of wind energy depends strongly on the load factor and costs at low wind speed sites are high. Biomass fired power generation could be competitive if the biomass is available at very low costs but purpose grown biomass in developed countries is expected to be relatively expensive. Coal fired power generation with CO2 capture and storage could be cost competitive if coal costs are low. Solar thermal energy is more expensive than the other options for stand-alone plants but it may be competitive when used in combination with fossil fuel fired plants. Solar photovoltaics are currently more expensive than the other technologies for large scale power generation but they can be attractive for small niche applications. Costs of all of these technologies are expected to decrease in future.

INTRODUCTION Large reductions in CO/emissions will be needed to achieve the UNFCC goal of stabilisation of atmospheric greenhouse gas concentrations. Over a third of the emissions of CO2 to the atmosphere from use of fossil fuels are from electricity generation so this is a priority area for emission reductions. In 1999, 64% of electricity was generated from fossil fuels (coal, oil and natural gas), hydro and nuclear each generated 17% and the remaining 2% was generated from renewables and waste [1]. The future of nuclear power is uncertain. It may be difficult to significantly increase nuclear power output because of public concerns about radioactive waste disposal, proliferation of nuclear materials and safety. Although some new nuclear plants will be built, this is expected to be countered by closure of existing plants. There will be some increase in hydro electricity production but the increase will be constrained by availability of sites and environmental concerns. If large reductions in CO2 emissions from electricity generation are to be achieved there will need to be a large increase in renewable energy production and/or large reductions in emissions per kWh from fossil fuel power stations. Specific emissions fi'om fossil fuel power stations will reduce as a result of improvements in thermal efficiencies but to achieve large reductions, CO2 will have to be captured and stored for long periods of time, several hundred years or more. This paper discusses the costs, emissions and constraints on renewable energy technologies and capture and storage of CO2.

1126

WIND ENERGY

Wind turbines have the advantage of producing no CO2, apart from a small amount produced during manufacture of the turbines. Their main disadvantages are that they can have a major visual impact on the landscape, they only generate electricity when the wind is blowing and the best sites with high wind speeds are ot~en remote from centres of electricity consumption. At the end of 2001, there was about 25 GW of installed wind turbine capacity worldwide [2]. Over the previous 5 years, the global capacity has grown at an average rate of more than 30% per year. The potential amount of electricity that could be generated from wind energy is many times greater than the current or projected future demand. For example, the total amount of electricity that could be generated from wind energy in the EU-15 is predicted to be 40,000 TWh/y, which can be compared to a demand of about 2,300 TWh/y. Environmental and technical constraints (exclusion of ground with steep slopes, urban areas, forests, conservation areas etc) reduce the potential to 30,000 TWh/y. Social constraints, such as proximity to dwellings and limits on the maximum number of wind turbines in a given area, are predicted to reduce the potential to 1,300 TWh/y, based on the current turbine density of high wind power regions of Denmark [3]. Even in the relatively densely populated region of the EU, with a high per capita electricity consumption, it is apparent that wind energy could provide a large proportion of the electricity demand. The social constraint may change in future depending on public perception of wind turbines. Costs of wind turbines have decreased substantially in recent years and are continuing to do so. The cost of a wind turbine is currently about $700/kW of peak power output and the total cost of a large onshore windfarm, including grid connection, is typically about $1,000/kW [3,4]. The annual load factor of a wind turbine depends strongly on the wind speed. The annual average load factor would be about 20% at an annual mean wind speed of 6 m/s and nearly 40% at an annual mean wind speed of 8 m/s. Wind is an intermittent energy source; typical electricity grids can easily accommodate small amounts of wind energy but as the amount of wind energy increases, the overall system effects increase. To cope with times when wind energy availability is low, extra fossil fuel-fired back-up generating capacity would have to be installed and the fossil fuel-fired plants on the grid would have to spend more time operating as peaking plants, at lower efficiencies. At high wind energy penetrations, some of the potential wind generation may have to be curtailed or energy storage systems may have to be used. The costs of these system effects are predicted to be less than 0.5 USc/kWh of wind energy at 45% wind penetration [5].

SOLAR ENERGY Two types of technology can be used to generate electricity from solar energy: solar thermal and photovoltaics (PV). PV cells convert solar energy directly to electricity. Solar thermal processes either produce steam, which is expanded in a conventional steam turbine, or they heat air in a gas turbine. The potential amount of electricity that could be produced by PV is very much greater than electricity demand, even if only 1% of the suitable land was used [6]. The potential of solar thermal generation is less because it can only use direct sunlight at sites with high solar irradiation, whereas PV can also utilise diffuse sunlight. The global potential electricity generation would still be many times greater than demand but it would be concentrated in Africa, Australia and the Middle East. The installed capacities of photovoltaic and solar thermal generating plants are currently about 1,000 MW and 350 MW respectively. The price of large scale photovoltaic modules is about $3,500-4,000/kW of peak power. The overall average price of modules, including small modules at retail prices, is about $6000/kW and total system prices range from 6,000 to 12,000 $/kW of peak power [6]. Costs of projected new solar thermal plants range from about $2,000/kW to $4,700/kW for stand-alone steam cycle plants and from $700/kW to $1,900/kW for Integrated Solar Combined Cycle Systems, where solar energy is used to supplement the steam cycle of a gas fired combined cycle plant [6]. In common with wind energy, solar energy is an intermittent energy source and a typical load factor for solar power generator without storage would be 25% [6]. Solar thermal energy

1127 systems can include some energy storage but this increases the capital cost per kW. For the comparison of options later in this paper, a capital cost of $2,000/kW and a load factor of 35% were assumed.

BIOMASS E N E R G Y

Biomass by-products such as sawdust, bark, straw and bagasse are already widely used for heat and power generation. Fast growing biomass such as poplar, eucalyptus, acacia, and miscanthus can also be grown specifically for use as fuel. The amount of CO2 emitted from biomass fired power stations is high, usually more per kWh than from coal fired power stations, but the CO2 is absorbed during growth of the biomass. Biomass from sustainable harvesting systems can therefore be regarded as an almost CO2-neutral fuel. The potential to generate electricity from biomass would be constrained by the available resource in many parts of the world. The amount of additional biomass fuel that could be produced in 2050 is projected to be 396 EJ/y [7]. If this were all used for power generation at an efficiency of 30%, it would generate 33,000 TWh/y of electricity, which can be compared to the global consumption of 14,800 TWh in 1999 and the projected consumption of 27,300 in 2020 [1,7]. However, only 13% of the potential generation from biomass (4,300 TWh/y) would be in the developed countries, economies in transition and the rest of Asia, which account for most of the world population and about 90% of its electricity demand. This quantity of biomass would require 1.28 Gha of land, which is large compared to the projected requirement of 1.7 Gha for agriculture in 2100 [7]. In most of the world, production of substantial amounts of biomass fuel would involve land use conflicts which could have serious implications for the supply and price of food, as well as the price of biomass. A study by IEA GHG [8] showed that in Spain only 5% of the current electricity demand could be satisfied using short rotation biomass without having to use good quality agricultural land. Current biomass power stations are normally based on stoker or fluidised bed combustion steam cycles. Biomass power stations tend to be relatively small, e.g. 25-60 MWe, because the amount of biomass that can be produced within a given radius of a power station is limited and biomass is bulky and expensive to transport compared to fossil fuels. The small size results in relatively low thermal efficiencies. Biomass can be co-used in large coal fired power stations, which results in better economies of scale and higher efficiencies, provided such plants are available. Integrated gasification combined cycles are being developed to increase the efficiency of power generation from biomass. Costs are currently higher than for conventional combustion plants but they may decrease in future when the technology is fully proven. The comparison of options later in this paper is based on a 60 MW stand-alone combustion plant with a capital cost of $1,650/kW and an efficiency of 30%, LHV basis [9].

CAPTURE AND S T O R A G E OF CO2 CO2 can be captured in fossil fuel fired power stations and stored for hundreds or thousands of years, for example in depleted oil and gas fields, deep saline aquifers or unminable coal seams. The main techniques that have been proposed for capturing CO2 in power stations are: • • •

Scrub the flue gas with a regenerable chemical solvent, such as monoethanolamine (MEA). Burn fossil fuels using oxygen, to produce a flue gas containing more than 90% CO2. Partially oxidise the fossil fuel to a fuel gas, and react this gas with steam to give hydrogen and CO2. After separating the CO2, the hydrogen can be used in a gas turbine or fuel cell.

These CO2 capture techniques use mainly proven technologies, although there is a need to integrate them and demonstrate their use at a large scale. CO2 can be transported to storage sites by pipeline or ship; over 3000 km of CO2 pipelines are already operating successfully, mainly in the USA. CO2 is already being stored underground, for example nearly 1 million tonnes per year is being stored at the Sleipner field in the Norwegian sector of the North Sea. Further work is needed to develop and test monitoring and verification techniques to give confidence that CO2 can be safely stored underground for long periods of time.

1128 The main technical constraint on the use of C O 2 capture and storage is the capacity to store CO2. About 900 Gt of CO/could be stored in depleted oil and gas reservoirs, equivalent to over 100 years of current global emissions from power generation [ 10]. The capacities of other potential CO2 storage reservoirs are less well know, for example it is estimated that 400-10,000 Gt of CO2 could be stored in saline aquifers [ 10]. The capital cost and efficiency of a coal fired power station with CO2 capture using MEA are estimated to be $1,860/kW and 33% (LHV basis). The capital cost and efficiency of a natural gas combined cycle plant with MEA scrubbing are estimated to be $790&W and 47% [ 11 ]. Overall costs of generation for plants involving partial oxidation/gasification are at present broadly similar to costs of plants using MEA scrubbing [11]. These costs include CO2 compression but do not include the costs of CO2 transport and storage. If the CO2 is used for enhanced oil recovery or enhanced coal bed methane production, the net cost of CO2 transport and storage could be zero, or even negative if there is revenue from the sale of oil or gas. If CO2 is transported 300km from a single power plant, and is stored in an onshore reservoir that does not produce any economic revenue, the cost may be around $8/t of CO2 stored. If CO2 is transported a long distance or is stored in a distant offshore reservoir the costs may be higher, say $20/t of CO2 stored.

COMPARISON OF COSTS Figure 1 shows the current costs of each of the electricity generation technologies. Solar photovoltaics is not included because its costs are several times higher than those of the other technologies. Costs of wind energy are shown for 3 load factors: 40%, which can be achieved at good sites, 30% which is typical of a moderate/good site and 20%, typical of a moderate/poor site. Coal, gas and biomass fired power stations are not constrained by the timing of energy resource availability and are assumed to operate at base load with load factors of 85%, 90% and 85% respectively. Figure 1 is based on a 10% discount rate in constant money values, a life of 20 years for wind turbines and 25 years for other technologies.

12 10 .... ....... - --~---m---#--

[- . . . . . . . . . . . . . . . . . . . . . . . . .

.. 8 r~ 0

..~

6

°1,1 "

4

~

2

0

1

2

3

4

Coal+CO2 storage Gas+CO2 storage Biomass Solar thermal Wind (20% load) Wind (30% load) Wind (40% load)

5

Fuel cost, $/GJ

Figure 1- Comparison of electricity generation costs based on current technologies At fuel costs of less than $3/GJ, natural gas fired combined cycle plants with CO2 capture and storage have the lowest electricity generating cost. If the cost of gas is higher, wind turbines at favourable sites with high load factors are cheaper. However, the cost of wind energy depends strongly on the load factor, and costs at low wind speed sites are high. Biomass may be an attractive fuel for power generation if it is available at very low costs but purpose grown biomass in developed countries is expected to be relatively expensive, around $3/GJ [8], resulting in high electricity costs. Coal fired power generation with CO2 capture and storage may be cost competitive if coal costs are low. Solar thermal energy is more expensive than the other options for stand-alone plants but it may be competitive when used in combination with fossil fuel fired plants, in which case the costs may be around half of those shown in figure 1. Local factors determine fuel costs and the availability of renewable energy resources and COz storage reservoirs. The optimum combination of technologies will be different for different countries.

1129 The costs shown in figure 1 for coal and gas fired plants are based on a CO2 transport and storage cost of $8/t CO2 stored. If the cost was $20/t, the cost of generation would be 1.0 c/kWh higher for a coal fired plant and 0.5 c/kWh higher for a gas fired plant. If CO2 could be transported and stored at no net cost, the generating cost would be 0.7 c/kWh lower for a coal fired plant and 0.3 c/kWh lower for a gas fired plant. The costs of wind and solar energy exclude penalties for intermittent generation. As discussed earlier, the penalty for wind energy is predicted to be less than 0.5 c/kWh at 45% wind energy penetration.

FUTURE COST P R O J E C T I O N S The costs of all of the technologies considered in this paper are expected to decrease in future because of technological improvements and larger markets. Projections of possible costs in 2020 are shown in figure 2. However, it must be emphasised that any projections of costs 20 years into the future involve speculation and cost improvements will depend on the extents to which the technologies are applied. The cost of wind turbines may fall by around 20-40% by 2020 [3,12]; figure 2 is based on a 30% cost reduction. Efficiencies of plants with CO2 capture will improve because of improvements in capture technologies and general improvements in power station efficiencies. In the case of coal plants, a move towards IGCC would also contribute to improved efficiencies. It is difficult to quantify potential reductions in the costs of capture technologies but in the analogous technology of flue gas desulphurisation, capital costs decreased by 75% between 1970 and 2000 [13]. For the cost projections in figure 2 it was assumed that the specific capital costs of power stations without CO2 capture would remain constant, the incremental capital cost of capture would decrease by 50%, efficiencies would increase by 10 percentage points and the costs of CO2 transport and storage would remain constant. For biomass, it was assumed that the state of the art would become biomass IGCC, with an efficiency of 45%, allowing for improvements in gas turbines. The capital cost of biomass IGCC is currently significantly greater than the cost of combustion plants but it was assumed that by 2020 the capital cost of biomass IGCC would be the same as the current cost of combustion plants. Costs of solar thermal energy are subject to more uncertainty than the costs of the other technologies. The overall potential for cost reduction is estimated to be in the range of 40-55% in the long term, based on a number of technical and economic improvements [6]. For figure 2 it was assumed that costs could reduce by 40% by 2020.

.= 8

!

I

Coal+CO2 storage 6

....

r~

o 5

¢,J

Gas+CO2 stoarge

. . . . . . . Biomass

~4 •~. 3 .~

2

.....

Solar thermal

.....

Wind (30% load)

1

0

1

2

3

4

5

Fuel cost, $/GJ

Figure 2: Comparison of electricity generation costs, 2020 The 2020 costs in figure 2 are lower than current costs for all of the technologies. The main differences compared to current costs are that solar thermal and to a lesser extent wind energy are more competitive.

1130 EMISSIONS

In plants with capture and storage of CO2 about 15% of the CO2 would still be emitted to the atmosphere, although this could be reduced if required. All of the power generation technologies emit some CO2 and other greenhouse gases indirectly, during fuel production and transportation and power plant construction. These direct and indirect emissions are summarised in table 1 [6, 8, 11, 14, 15].

TABLE 1 CO2 EMISSIONSFROMELECTRICITYGENERATION

Direct emissions, g/kWh Indirect emissions, g/kWh

Coal with CO2 capture 150 60

Gas with CO2 capture 60 10

Biomass

Solar thermal

Wind

10

30

10

CONCLUSIONS

The lowest cost methods of generating electricity with low emissions of CO2 are natural gas fired combined cycle plants with capture and storage of CO2 or wind turbines at sites with high wind speeds. Biomass-fired power stations and coal fired power stations with capture and storage of CO2 can be competitive at low fuel costs. Solar thermal energy is currently not cost competitive, except possibly in combination with fossil fuel plants. The costs of all of these technologies are expected to decrease in future.

ACKNOWLEDGEMENT

The views expressed in this paper are those of the author and do not necessarily represent those of the International Energy Agency, the lEA Greenhouse Gas R&D Programme or its Members.

REFERENCES

1. IEA (2201). Key Worm Energy Statistics 2001, International Energy Agency, Paris, www.iea.org 2. BTM Consult (2002). International wind Energy development: World Market Update 2001, BTM Consult, Denmark, April 2002, www.btm.dk 3. Fellows, A., Gow, G., Ellis, A. and Davison, J., (2001). The Potential of Wind Energy to Reduce CO: Emissions, European Wind Energy Conference, Copenhagen, 2-7 July 2001. 4. European Wind Energy Association (2002), www.ewea.org/src/economics.htm 5. Milborrow, D., (2002), www.piu.gov.uk/2002/energy/report/working%20papers/Milborrow.pdf 6. IEA Greenhouse Gas R&D Programme (2002), The Potential of Solar Energy to Reduce C02 Emissions, forthcoming study, Cheltenham UK. 7. Intergovemmental Panel on Climate Change (2001), Climate Change 2001: Mitigation, Cambridge University Press, UK 8. Varela, M,, Sfiez, R. and Audus, H. (2001), Solar Energy 70(2), 95-107. 9. IEA Greenhouse Gas R&D Programme (1999), Report no. PH3/11, Nov. 1999, Cheltenham, UK. 10. IEA Greenhouse Gas R&D Programme (2001), ISBN 1898373 07 8, www.ieagreen.org.uk 11. Audus, H., (2000). Leading options for capture of C02 at power stations, GHGT-5 Conference, Cairns, Australia, 13-16 August 2000, CSIRO Publishing, Australia. 12. European Wind Energy Association and Greenpeace (2002), Wind Force 12, EWEA, Brussels 13. Soud, H.M. (2000), IEA Coal Research report CCC/29, ISBN 92-9029-339-X. 14. IEA Greenhouse Gas R&D Programme (1995), ISBN 1 898373 03 5, www.ieagreen.org.uk 15. European Commission DG XII, (1995), ExternE: Externalities of Energy, Luxembourg

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1131

COST AND PERFORMANCE OF CO2 AND ENERGY TRANSMISSION D.J. Freeman 1, D.A. Findlay l, M. Bamboat 1, J. Davison 2 and I. Forbes 3 1Woodhill Engineering Consultants, St. Andrew's House, West Street, Woking, GU21 1EB, UK 2IEA Greenhouse Gas R&D Programme, Stoke Orchard, Cheltenham, GL52 7RZ, UK 3Mort MacDonald, Victory House, Trafalgar Place, Brighton BN 1 4FY, UK

ABSTRACT The need to reduce emissions of greenhouse gases could have major effects on energy transmission. CO2 from fossil fuels may need to be captured and transported to long term stores, for example deep saline aquifers or depleted oil and gas fields. This may affect the optimum location of energy conversion plants such as power stations. Also, novel energy carriers such as hydrogen may become more attractive. On behalf of the IEA Greenhouse Gas R&D Programme, Woodhill Engineering Consultants, in collaboration with Mott MacDonald, have developed a model for initial assessment of the costs and performance of energy transmission and CO2 capture. The model covers the distribution of energy in various forms such as natural gas, hydrogen, methanol, distillate oil, and electricity, and the capture and gathering of CO2 using onshore and offshore pipeline transmission. Sensitivities can be assessed for a wide range of factors, such as the output of power stations, fuel supply flowrate, pipeline diameter, operating pressure, terrain and country. Cost estimation is based on industry standard techniques. The model also includes simple algorithms for the costs and performances of energy conversion plants, such as power stations and hydrogen plants, and for underground injection of CO2. This paper contains a description of the model and includes several examples of predicted costs and performance of energy distribution and CO2 capture and transmission. INTRODUCTION

Future strategies for fuel transmission and CO2 sequestration have always and will continue to be influenced by capital and operating costs (capex and opex). In addition to the costs of energy conversion (e.g. hydrocarbon fuel to electricity), other costs to be considered include fuel transportation, electricity distribution and CO2 sequestration. All these costs can vary considerably with relatively small changes in the strategy selected. On behalf of the IEA Greenhouse Gas R&D Programme (lEA GHG), Woodhill Engineering Consultants, in collaboration with Mott MacDonald, have developed a model for the initial assessment of the costs and performance of energy transmission and CO2 capture. This paper includes details of the model, a discussion of the key factors that affect costs, and examples of predicted costs. The model addresses capex and opex for energy distribution and CO2 sequestration. These cost estimates can be used in economic modelling which may include other factors not addressed in this paper, such as emissions trading, carbon tax, local logistics and planning.

1132 CO2 TRANSMISSION The use of pipelines for transportation of gaseous and liquid hydrocarbon fuels has long been established. Pipelines for transmission of CO2 are also in operation, and factors to be addressed include:

C02 Quality In the presence of liquid water, CO2 forms carbonic acid which can cause corrosion of carbon and low alloy steels. CO2 corrosion has been studied extensively, and the precautions needed to satisfactorily transport CO2 in carbon steel lines are well documented [ 1]. CO2 should not cause corrosion of carbon and low-alloy steel lines, provided the gas is dry. Operating below 60% relative humidity normally provides a margin to avoid water condensation or dropout from the gaseous phase. Without free water in the system, carbon steel is an acceptable material for CO2 pipelines. C02 Phase Behaviour The phase behaviour of CO2 can cause considerable process concerns, particularly with respect to possible phase changes. The Model described in this paper assumes that following capture, CO2 is dried and its pressure boosted to achieve a dense phase fluid for efficient pipeline transport to a storage site [2]. At pressures and temperatures above the critical point, CO2 will exist as in the dense phase region. ENERGY DISTRIBUTION SYSTEMS An Energy Distribution System (EDS), for the purposes of this paper, is considered to supply electrical power to consumers using a fossil fuel source. An EDS typically comprises the following elements: Fuel sources, e.g. natural gas, oil or coal. Systems to transport the fuel from the source. Fuel synthesis plants, for the manufacture of e.g. methanol or hydrogen from natural gas. Power stations, using natural gas, oil, methanol, hydrogen or coal to generate electricity. Electrical transmission system. Systems for sequestration of CO2 from fuel synthesis plants or power plants for disposal. CO2 storage facilities. There may be many options available to supply energy from any given source, as shown in Figure 1. In this example, natural gas is used as the fuel source to generate electrical power for three separate 400 MW consumers. Four possible options to supply this power are shown: A centralised 1200 MW natural gas-fired power station, with centralised CO2 sequestration facility. Electricity is supplied to the consumers via relatively long transmission lines. Local 400 MW power stations for each consumer. The transmission lines will be shorter, but longer pipelines will be needed for fuel and CO2 transmission. A centralized power station, fuelled by hydrogen which is manufactured from natural gas at a synthesis plant close to the fuel source. No CO2 is produced at the power station, and CO2 captured at the synthesis plant can be stored using relatively short pipelines. Local hydrogen-fuelled power stations. These illustrate that the options for supplying energy to consumers from a given fuel source may be extremely varied, and when selecting the most appropriate option there are many considerations to be made, including: capex and opex; safety; environmental impact; logistics of construction; etc. The use of smaller, local power stations reduces losses in transmission lines, but means that pipelines for fuel and CO2 may be longer, with higher compression requirements. The costs associated with three small power stations compared with a single large one will also be different. The optimum location for a single facility may also be difficult to determine, with a balance required between long transmission lines and long pipelines.

1133 Figure 1: Example Energy Distribution System la: Centralised fossil fuel power station Consumers Power station (1200 MW)

Fuel Source Fuel pipeline (200 km)

V A "'~ - - - . a ~ o 0 Electrical Transmission /I

km

COz pipeline (200 km) 50 km !

/~

C02 recovery and compression

CO2 injection facility

lb: Distributed fossil fuel power stations Power stations (400 MW)

:i"

|. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |

1¢: Centralised, hydrogen fuel power station Power station (1200 MW) ~

10 km d H2 synthesis [ H2 Pipeline (190 km) "1 plant !

~"

A

COz pi~elin_e_(IOkm_)__ |

ld: Distributed hydrogen fuel power stations Power stations (400 MW)

"-i'll Hz syntheSiSplant] i |

r- . . . . . . . . . . |

r

ps~

1134 Using hydrogen as a fuel is an attractive alternative from an environmental point of view, because no CO2 will be produced at the power stations. The hydrogen synthesis plant will produce CO2, but if the CO2 is stored close to the fuel source then the CO2 pipelines are likely to be shorter than from a power station. Transmission of hydrogen in pipelines presents several difficulties, particularly in terms of pipeline design and hydrogen compression. Several significant metallurgical considerations (such as hydrogen induced cracking) need to be taken into account when designing pipelines for hydrogen service. However, carbon steels with a low sulphur content and alloyed with other metals are commonly used for hydrogen service. Similarly, centrifugal compressors are not generally suitable for hydrogen compression as the pressure rise per stage is very small due to the low molecular weight of the gas: reciprocating compressors are often used. When considering the viability of hydrogen as an alternative fuel, these considerations may mean that costs change significantly, and these must be taken into account, along with other factors such as potential environmental benefits. COST ESTIMATION

Estimation of capex and opex is essential for the comparison of options for COz and energy transmission. A model has been developed that allows an initial assessment of the costs and performance of energy transmission and COl capture, by allowing the user the overall flexibility to build each option by defining the following assets: • • • •

Power station (including a CO2 export pipeline and power transmission) Fuel synthesis plant (with associated export pipeline) CO2 storage facility (with pipeline and storage wells) Pipeline system

By defining the necessary assets, the costs for any complete EDS can be estimated. The model takes into account global factors such as the location and fuel costs, and determines capex and opex for each asset and for the EDS as a whole. P o w e r station

The power station has been designated as using either Combined Cycle Gas Turbine (CCGT) or Pulverised Coal Steam Cycle technology. As an intrinsic element of the model, all power stations incorporate recovery of COz from the exhaust gases of the plant. The CO2 recovery process is assumed to use amine absorption. Capex and opex estimates are based on IEA GHG data for natural gas and coal fired electrical power stations, with factors applied for power stations of other fuels, i.e. methanol, distillate oil, and hydrogen.

Fuel synthesis A fuel synthesis plant within the model can manufacture either methanol or hydrogen. Both these products are synthesised from a natural gas feedstock. The process assumes that natural gas feedstock is converted to synthesised fuel at fixed conversion efficiencies on an energy basis [3]. Methanol synthesis plant costs are based on the conventional technology of Steam Methane Reforming (SMR) [4]. The H2 synthesis plant cost estimates are based on IEA GHG data for a plant producing H2 from natural gas, including separation of CO2.

COz sequestration

CO2 injection is assumed to take place into retaining aquifers. In general these are considered to be saline aquifers with sufficient integrity and retention such that seepage of CO2 back to the atmosphere is negligible. A second option is the use of redundant hydrocarbon reservoirs that have ceased production. The choice of a suitable aquifer is influenced by many factors such as well performance, location, etc., and is beyond the scope of this paper. Aquifers defined in the model can be located either onshore or offshore and are assumed to be approximately 1000m in depth.

1135 Injection wells can be onshore or offshore. The costs for offshore injection include the costs of a wellhead platform or subsea wells and a subsea pipeline. Offshore well costs are greater than onshore well costs.

Pipelines Pipelines may be offshore or onshore, and may include compression facilities along their length, for pipeline cost optimisation. The pipeline size and the number of booster stations are calculated using standard sizing routines or by setting them manually. The variables used to determine the size and cost of the pipeline and booster stations include the fluid (fuel, CO2 etc), length, mass flowrate through the pipeline, the terrain through which it will be laid and the required outlet pressure. Example costs for the four options shown in Figure 1 are presented in Tables 1 and 2: TABLE 1 CAPEX COST ESTIMATESFOR FOURALTERNATIVEENERGYDISTRIBUTIONSYSTEMS

Option (see Figure 1)

la

lb

lc

ld

Power Stations (inc. CO2 capture)

856

1020

450

536

Hydrogen Synthesis Plant

N/A

N/A

787

787

95

75

95

75

Electrical Transmission Natural Gas Pipelines (inc. booster compression) Hydrogen Pipelines (inc. booster compression) CO2 Storage (Pipelines, compression and wells)

70

109

14

14

N/A

N/A

135

146

127

168

73

74

Total

1148

1372

1554

1632

TABLE 2 OPEX COSTESTIMATESFOR FOURALTERNATIVEENERGYDISTRIBUTIONSYSTEMS

Option (see Figure 1)

la

lb

lc

ld

Power Stations (inc. CO~ capture)

188

207

26

35

Hydrogen Synthesis Plant

N/A

N/A

309

309

Electrical Transmission

0.3

0.0

0.3

0.0

Natural Gas Pipelines (inc. booster compression) Hydrogen Pipelines (inc. booster compression) CO2 Storage (Pipelines, compression and wells)

N/A

N/A 12

13

13

Total

196

222

354

364

1136 Comparing options l a and l b in the above example, the reduced capex for electrical transmission is significantly outweighed by the greater capex for three smaller power stations compared with a larger centralised station and the greater capex for fuel and CO2 pipelines. The model can take the terrain through which pipelines are laid into account, and can therefore be used as a tool for determining optimum (from a cost point of view) locations and routes for power stations and pipelines. The costs shown in Table 1 for options l c and l d show that in this example the total capex and opex are greater if hydrogen is used to generate electricity. The cost of the synthesis plant is a major factor, and pipelines suitable for transportation of hydrogen have a higher cost than natural gas pipelines. However, a decision to use hydrogen will not be determined by facilities cost alone: the environmental benefits of producing all the CO2 at a single point close to the disposal location, where it can be easily captured and stored, has significant environmental benefits. The costs calculated for this example show that the capex for CO2 storage are significantly lower for options 1c and 1d. CONCLUSIONS Transmission and disposal of CO2 is a challenge for engineers, and there are many considerations to be made, including capex and opex, safety, environmental impact, logistics of construction, etc. The model presented in this paper can be used for initial assessment of the costs of energy transmission and CO2 capture, and allows quick and easy comparison of different options for gathering COz from multiple sources and of various energy transport development cases. The sensitivity to a wide range of factors, such as output of power stations, fuel supply flowrate, pipeline diameter, operating pressure, terrain and country can also be assessed. The cost estimation is based on well-established industry standard sizing techniques and the contractors' in-house estimating methods using industry norms, and the clear audit trail within the model means that the costs can be used with confidence. REFERENCES

1.

RH Perry (Ed), Perry's Chemical Engineers' Handbook, 7th Edn, 1997 IEA Greenhouse Gas R&D Programme Report, Carbon Dioxide Disposal From Power Stations, IEA Greenhouse Gas R&D Programme, Cheltenham, UK

3.

ARCADIS Geraht & Miller, Inc., Fuel Cycle Energy Conversion Efficiency Analysis, 25 May 2000

4.

Foster Wheeler, Foster Wheeler StarChem Methanol Process, 30 July 2001

POLICY- OVERVIEW

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1139

E X P E R I E N C E C U R V E S FOR E N V I R O N M E N T A L T E C H N O L O G Y AND THEIR R E L A T I O N S H I P TO G O V E R N M E N T ACTIONS E.S. Rubin l, M.R. Taylor 2, S. Yeh 1 and D.A. Hounshell 1 l Department of Engineering and Public Policy, Carnegie Mellon University Pittsburgh, PA 15213, USA 2 Richard & Rhoda Goldman School of Public Policy, University of California, Berkeley Berkeley, CA 94720-7320

ABSTRACT We seek to improve the ability of integrated assessment models (IA) to incorporate changes in CO2 capture and sequestration (CCS) technology cost and performance over time. This paper presents results of new research that examines past experience in controlling other major power plant emissions that might serve as a reasonable guide to future rates of technological progress in CCS systems. In particular, we focus on U.S. and worldwide experience with sulfur dioxide (SO2) and nitrogen oxide (NOx) control technologies over the past 30 years.

INTRODUCTION

Large-scale energy-economic models used to study global climate change and carbon management options often ignore the impacts of environmental technology innovation and diffusion, or they use simple representations such as exogenously-specified (often arbitrary) rates of change in cost or efficiency over time. The predicted impacts of proposed policy measures can depend critically upon these assumptions. Thus, better methods are needed to model technological change and its relationship to government policy. This is especially true for CO2 capture and sequestration (CCS) technology, an important new class of environmental technology with the potential to allow continued use of fossil fuels without significant greenhouse gas emissions to the atmosphere. Research efforts are underway worldwide to develop this technology and evaluate its effectiveness. Large-scale energy-economic and integrated assessment models also are being used to evaluate the potential of CCS in competition with other options for CO2 control. We seek to improve the ability of such models to represent and quantify the changes in CCS technology cost and performance over time as a function of pertinent variables, including the effects of alternative government actions or policies. Toward this end, this paper presents results of new research that examines past experience in controlling other major power plant emissions that might serve as a reasonable guide to future rates of technological progress in CO2 capture and sequestration systems. In particular, we focus on U.S. and worldwide experience with sulfur dioxide (SO2) and nitrogen oxide (NOx) control technology over the past 30 years, seeking answers to the following related questions: (1) how did the deployment, performance, and cost of these environmental technologies change over time? And, (2) how were these changes and technological innovations related to government actions and policies?

1140 DEVELOPMENT

OF EXPERIENCE

CURVES

Two widely used emission control technologies at coal-fired power plants are flue gas desulfurization (FGD) systems used to control SO2 emissions and selective catalytic reduction (SCR) systems used to control NOx emissions. Both technologies are post-combustion control systems applied to the flue gas stream emanating from a coal-fired boiler or furnace. In contrast to environmental controls that are applied either prior to or during combustion, FGD and SCR systems represent the technologies having the highest pollutant removal efficiencies currently available for coal-burning plants. They are also the most expensive technologies for emissions control, and for this reason requirements for their use have been highly controversial.

Historical Deployment of FGD Systems. FGD systems (also known as scrubbers) encompass a variety of technologies that have been extensively described and discussed in the literature [1]. By far the most prevalent technology, accounting for approximately 86% of the world market, are socalled "wet" FGD systems employing limestone or lime as a chemical reagent. These systems can achieve the highest SO2 removal efficiencies (historically around 90%, but today as high as 98 to 99%), but they generate a solid residue that must either be transformed into a useful byproduct (gypsum) or disposed as a solid waste. So-called "dry" FGD systems typically use lime as the reagent in a spray dryer system that is less efficient than wet FGD systems but adequate to achieve the less restrictive SO: removal requirements for low-sulfur coals allowed by the New Source Performance Standards (NSPS). Because of their limited applicability, lime spray dryers and other forms of dry SO2 removal account for less than eight percent of the total FGD market [ 1].

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Figure 1.

Figure 1 depicts the worldwide growth in FGD installations over the past three decades. The y-axis measures the total electrical capacity of power plants whose flue gases are treated with wet lime or limestone scrubbers. Figure 1 also shows that the United States has led in the deployment of this technology. Today, approximately 30 percent (80,000 MW) of U.S. coal-fired capacity is equipped with FGD systems, most of which are wet scrubbers.

Relationship to SOz Control Requirements. The onset and growth of FGD use in each country reflects the adoption of national (and in some cases international) regulations that were sufficiently stringent so as to require or encourage the use of FGD as an emissions control strategy. In the United States, stringent requirements for SO2 control can be traced to the Clean Air Act Amendments (CAAA) of 1970 and 1977. Many existing power plants chose to retrofit FGD systems in order to meet state and local emission regulations designed to achieve the national ambient air quality standards for SO2 established under the 1970 CAAA. For new power plants, federal New Source Performance Standards (NSPS) set by the U.S. Environmental Protection Agency (EPA) required the use of "best available control technology" (BACT). The first NSPS for coal-fired power plants, established in 1971, defined BACT as a performance-based standard limiting SO2 emissions to 1.2

1141 pounds per million Btu (lb/MBtu) of fuel energy input to the boiler. This emission standard corresponded to roughly a 75 percent reduction from the average emission rates at the time, but allowed new plants to comply either by burning a sufficiently low sulfur coal, or by installing an FGD system while burning high-sulfur coals. In 1979, a revised NSPS was promulgated that replaced the performance-based standard with a technology-based standard requiring all new coal-fired plants built after 1978 to employ a system of continuous emission reductions achieving between 70 and 90 percent SO2 removal, with the percentage depending upon the sulfur content of the coal being burned. Effectively, this meant the use of an FGD system on all new coal-fired plants. The lower removal efficiency limit applied to plants burning low sulfur coals typical of those in the western United States, while the higher limit of 90 percent removal applied to plants burning higher sulfur coals characteristic of the Midwest and eastern U.S. More recently, the 1990 CAAA established a national emissions cap for SO2 to address the problem of acid deposition. To achieve this limit, existing power plants were required to further reduce their SO2 emissions by roughly 40 percent below their 1990 levels. Power plants could comply in a variety of ways (including emissions trading), but owners of some plants chose to install FGD systems. In other countries, stringent controls on SO2 emissions were implemented initially in Japan and later in Germany. The first modem utility-scale FGD systems were installed on Japanese power plants in the late 1960s and served as benchmarks for early FGD adoptions in the United States. In 1983, in response to growing concerns about the destruction of German forests from acid rain, Germany enacted stringent new regulations requiting the installation of FGD systems on all large coal-fired plants already in service. Subsequently, other European nations also adopted regulations requiting FGD on coal-fired power plants. Resulting Trend in FGD Cost. The deployment of FGD systems over the past several decades has been accompanied by improvements in performance and reductions in the cost of this technology. We use the concept of an "experience curve" (often called a learning curve) to characterize these reductions in cost. Such curves have been discussed extensively in the literature for a wide range of technologies, including energy technologies [2-6]. Cost reductions are typically described by an equation of the form: Yi = ax[ b, where yi = c o s t t o produce the ith unit, xi = cumulative production through period i, b = learning rate exponent, and a = coefficient (constant). According to this equation, each doubling of cumulative production results in a cost savings of (1 - 2-b), which is defined as the learning rate, while the quantity 2 -b is defined as the progress ratio. These cost reductions reflect not only the benefits of learning by doing at existing facilities, but also the benefits derived from investments in research and development that produce new knowledge and generations of a technology. The development of an experience curve for FGD systems is not straightforward because many of the factors that influence cost are not directly related to improvements in the FGD technology [7]. To obtain a more accurate picture of real FGD cost reductions, we use a series of studies performed by the same organizations over a period of years using a consistent set of design premises as the basis for FGD cost estimates. These studies reflect the contemporaneous designs and costs of FGD systems installed at U.S. power plants. Figure 2 shows the experience curve developed for FGD capital cost. All costs are adjusted to a common basis for a standardized 500 MW power plant burning a high sulfur coal (3.5 % S) with a wet limestone FGD system achieving 90 percent SO2 removal. Total capital cost shows a significant decline over time. Many of the process improvements that contributed to lower costs (especially improved understanding and control of process chemistry, improved materials of construction, simplified absorber designs, and other factors that improved reliability) were the result of sustained R&D programs and inventive activity, as documented and described elsewhere [7]. Increased competition among FGD vendors also may have been a contributing factor. Such influences are difficult to discern in most studies of experience curves because the available data typically represent the cost to technology users (i.e., technology prices) rather than the cost to technology developers.

1142 However, a careful look at the underlying technological changes over several decades indicates that the FGD cost reductions shown here primarily reflect the fruits of technology innovation.

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Figure 3. Cumulative installed capacity of SCR systems on coal-fired power plants from 1980 to 2000.

Historical Deployment of SCR Systems. Figure 3 shows the historical trend in the worldwide growth of SCR capacity. Here, the earliest use of SCR is seen in Japan beginning in the 1970s, followed by widespread adoption in Germany in the mid-1980s. The U.S. has been the laggard in SCR use, with the first units on coal-fired plants installed only in 1993. Over the next few years, however, U.S. capacity of SCR systems is expected to grow significantly in response to recently enacted NOx control regulations. SCR systems also have been installed on electric power plants burning oil and natural gas since these systems also produce NOx during combustion. The total capacity of SCR systems on non-coal utility systems for U.S. power plants was approximately 11.5 GW in 1996 [8], most of which was installed only in the last decade.

Relationship to NOx Control Requirements. As with FGD systems, the onset of growth in SCR capacity reflects the stringency and timetable for NOx regulations in different countries. In the United States, the control of power plant NOx emissions initially followed the same timetable and regulatory approach as for SO2, beginning with the 1970 CAAA and 1971 NSPS. The key difference was in the stringency of applicable requirements. Under the 1970 CAAA, existing power plants were largely unaffected by state-level requirements to achieve NO2 air quality standards. For new sources, the EPA performance standards imposed only modest requirements that could be met at low cost using low-NOx bumers (LNB) for combustion. As SO2 emission restrictions grew more stringent (and more costly) during the 1970s and 1980s, NOx emission requirements for coal plants did not change appreciably until the 1990s.

1143

The acid rain provisions of the 1990 CAAA required many existing coal-fired plants to install "reasonably available control technology" in the form of low-NOx burners and other combustion modifications. In 1994, EPA established much more stringent emission reduction requirements (averaging about 85 percent) for existing power plants as part of a regional strategy to attain the health-related air quality standards for ground-level ozone. Achieving these stringent NOx reductions requires retrofitting SCR systems at many existing power plants. A massive expansion in SCR installations is thus now underway in the United States. A 1997 revision to the Federal NSPS also now requires a high level of NOx control that is currently achievable only with SCR systems in most cases. In contrast to the U.S. situation, the use of SCR in other industrialized countries began many years ago in response to stricter NOx emission limits. Japan first enacted strict requirements in the 1970s and pioneered the development of SCR technology for power plant applications. In the mid1980s, Germany required the use of SCR systems on large coal-fired power plants as part of its acid rain control program. Subsequently other European countries also began to adopt this technology, as seen in Figure 3. 100%

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A P P L I C A T I O N TO I N T E G R A T E D ASSESSMENTS MODELS The resulting learning rates of 11% and 12% for FGD and SCR systems, respectively, are similar not only to each other, but also to the average learning rates found in other studies for a wide range of market-based technologies [4, 10]. We believe the quantitative results presented here can provide useful guidelines for assessing the influence of technological change on future compliance costs for new environmental control requirements for coal-based power plants. In this context, our preliminary experience curve for FGD systems was used as a surrogate for the rate of capital cost decline that might be expected if CO2 capture and storage (CCS) systems were deployed at power plants as part of a future strategy to reduce greenhouse gas emissions. Preliminary results from an integrated assessment modeling study carried out by researchers at IIASA [11] indicated that the cost of achieving a climate stabilization target was significantly lowered when the historical learning rate for SO2 capture systems was applied to CCS systems for fossil fuel power plants. Several methodological issues remain to be further explored in the context of modeling studies with long

1144

time horizons such as the 50- to 100-year time frames commonly used for climate policy analysis. In particular, it is unlikely that the learning rates observed during the initial development and deployment of a new environmental technology (like CO2 capture) will be sustained indefinitely as the technology matures [12]. Future studies will explore this and other issues as part of our continuing research in this area. ACKNOWLEDGEMENT

This project was supported by the Office of Biological and Environmental Research, U.S. Department of Energy, under Grant No. DE-FG02-00ER63037. The authors thank Dr. Leo Schrattenholzer and Dr. Keywan Riahi of IIASA for their collaboration on this project. REFERENCES

1. 2. 3. 4. 5. 6. 7.

9.

10. 11. 12.

Soud, H.N., FGD installations on coal-firedplants. 1994, IEA Coal Research: London. Arrow, K., The Economic Implications of Learning by Doing. Review of Economic Studies, 1962.29: p. 155-173. Dutton, J.M. and A. Thomas, Treating Progress Functions as a Managerial Opportunity. Academy of Management Review, 1984. 9(2): p. 235-247. Dutton, J.M., A. Thomas, and J.E. Butler, The History of Progress Functions as a Managerial Technology. Business History Review, 1984. 58(2): p. 204-233. Grfibler, A., N. Nakicenovic, and D.G. Victor, Dynamics of Energy Technologies and Global Change. Energy Policy, 1999.27(5): p. 247-280. Thompson, P., How Much Did the Liberty Shipbuilders Learn? New Evidence for an Old Case Study. Journal of Political Economy, 2001. 109(1): p. 103-137. Taylor, M., The Influence of Government Actions on Innovative Activities in the Development of Environmental Technologies to Control Sulfur Dioxide Emissions from Stationary Sources, in Department of Engineering and Public Policy. 2001, Carnegie Mellon University: Pittsburgh, PA. U.S. Environmental Protection Agency, EPA Clean Air Market Program: Emissions Data & Compliance Reports. 2002. U.S. Geological Survey, Minerals Information: commodity statistics and information. 2001. The Boston Consulting Group, Perspectives on Experience. 1972: Boston, MA. Riahi, K., E.S. Rubin, and L. Schrattenholzer, Technological Learning for Carbon Capture and Sequestration Technologies. Energy Economics, 2002. submitted. Klepper, S. and E. Graddy, The Evolution of New Industries and the Determinants of Market Structure. RAND Journal of Economics, 1990.21(1): p. 27-44.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1145

G R E E N H O U S E GAS INTENSITY T A R G E T S VS. A B S O L U T E EMISSION T A R G E T S N. Hrhne and J. Harnisch ECOFYS energy & environment, Eupener Str. 161, 50933 Cologne, Germany

ABSTRACT Emission limitation or reduction targets for countries under the international climate negotiations can be formulated as absolute targets, defining a fixed amount of allowed emissions (as in the Kyoto Protocol), or as intensity targets, defining an amount of allowed emissions per unit of the Gross Domestic Product (as recently proposed by the US government). In this paper, we discuss the pros and cons of these types of emission limitation or reduction targets. We find that intensity targets can provide advantages over absolute targets as they can lead to more certainty whether a target will be reached and they can account for unexpected economic changes. This is however only the case if emissions and GDP are well correlated, the strength of this correlation is know and used to set the target. For a limited number of examples we have shown that deriving the relationship between emissions and GDP (as needed for defining intensity targets) from historical data is difficult for most of these cases. Further analysis is necessary in order to be able set intensity targets in a way that maximises their advantages over absolute targets.

INTRODUCTION The United Nations Framework Convention on Climate Change (UNFCCC) calls for the stabilization of greenhouse gas concentrations at levels that prevent dangerous anthropogenic interference with the climate system. As a first step, the Kyoto Protocol defines greenhouse gas emission targets for industrialized countries. For further necessary steps, nations may want to agree on additional targets for possibly more countries. In this paper, we analyse the pros and cons of two ways to formulate emission limitation or reduction targets for countries under an international climate agreement: 'Absolute targets' and 'intensity targets'. Further, we analyse historical emission and GDP data using regression analysis. TWO TYPES OF T A R G E T S 'Absolute targets' define a fixed amount of emissions which is assigned to each country for a certain year (compare Eqn. 1). E.g. the Kyoto Protocol requires the European Union to reduce their total greenhouse gas emissions on average over the years 2008 to 2012 by 8% compared to 1990 levels, the USA by 7%. E m i s s i O n S allowed = E m i s s i o n S base year " F r a c t i o n

(1)

'Intensity targets' define an amount of allowed emissions as a function of one variable in the target year, usually the Gross Domestic Product (GDP), see Eqn. 2 and 3. The greenhouse gas (GHG) intensity is the amount of greenhouse gas emissions per unit of GDP. While for absolute targets the amount of allowed emissions in the target year is know in advance, for intensity targets this amount depends on the value of the GDP in the target year.

1146 EmissiOnS allowed GDPtarget year el

=

EmissionSbase

year

Fraction

GDPbas e year el

IGDetargetyearl el • Fraction EmissiOnS attowed = Emissi°nS baseyear • GOPbase year

(2) (3)

The main goal of setting a target as intensity target is that in the case the economy develops unexpectedly, the amount of allowed emissions changes as well. As a first approximation one can assume that if the GDP is 1% above the expected, the real emissions are also 1% above, therefore the target should be 1% higher. In this case the target is defined as decrease in GHG intensity, the elasticity el=l in Eqn. 1 and 2. As an example, the US government has recently proposed to reduce its greenhouse gas (GHG) intensity, measured as greenhouse gas emissions divided by the Gross Domestic Product, by 18% in the next 10 years [ 1], which is 2% per year. A reduction in the greenhouse gas intensity (Emissions per GDP) is the sum of two components: a reduction (or increase) of emissions and an increase (or reduction) of GDP. For example, a 5% reduction in the GHG intensity could be achieved by a 2% decrease in emissions and a 3% increase in GDP. Or a 2% reduction in the GHG intensity could be achieved by a 1% increase in emissions and a 3% increase in GDP. However, some sources of GHG emissions within a country may be not well correlated with the GDP. For this reason, Argentina had proposed a target in 1999 expressed as a function of the square root of the GDP (el=0.5) in the target year, since its agricultural emissions are not well correlated to the GDP [2]. An unexpected change in the economy by 1% changes the target by 0.5%. R E G R E S S I O N ANALYSIS To find out more about the relationship between emissions and GDP we analyse historic data of emissions and GDP. In long-term trends of the emission intensities for different countries (see [3]) we observe, that countries move through four basic stages during their development, where the emission intensity first increases, reaches a maximum and then decreases again: • In a first phase, the industrialization, energy use increases and GHG emissions grow faster than the GDP. Increasing proportions of the GDP are met with emission intensive activities. Consequently, the emission intensity increases. • In a second phase, the growth phase, the economic activity increases further, but emissions increase as fast as the GDP, the emission intensity is constant. • In a third phase, the decarbonization, the economy grows further but mainly in activities with low emissions. Both, GDP and emissions increase, but GDP faster than emissions, the emission intensity declines. • In a fourth phase, the emission reduction phase, the economy grows further, but the absolute emissions decrease, due to a restructuring away from emission intensive production. The emission intensity declines faster than the GDP grows. For a regression on historic data, we first assume a simple relationship between emissions and GDP: E(t) . c GDP(t) a. , .

.l(t)

E(t)

GDP(t)

c. GDP(t) a-'

(4)

where c and a are constants that are determined by the regression and I(t) is the emission intensity. A regression can be applied over periods of time where the emission intensity changes linearly. One question is whether coefficient a that we find here is the elasticity that is needed to set the intensity targets. For the regression we use C02 emissions from fuel combustion and GDP using purchase power parities from the same source [4]. India: The simple relationship between emissions and GDP was used for regression of data for India. For the period 1971 to 1991 we observe a coefficient a of 1.23. I.e. in that period, an increase in GDP of 1 % coincided with an increase in emissions of 1.23%. Between 1991 and 1997 the coefficient a i s only 1.01. (see

1147 Figure 2, left). The Indian economic is being restructured and in constant change. With the simple formula we cannot obtain the influence of the GDP on the emissions. 2500

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Figure 2" Emissions, GDP and intensity (Emissions/GDP) for India (left) and former USSR (right) Former USSR: Regression is also applied to data for the states of the former USSR. To ensure the consistency in the time series in this region, the aggregate of newly independent states is used after 1992. For regression from 1971 to 1990 to the simple formula (Eqn 3.) the coefficient a is 0.87 (Figure 2, right). The emission intensity decreased constantly at around 1% a year. Due to the economic collapse after 1990, the GDP and emissions decreased drastically. Since GDP decreased faster than emissions, the intensity increased. The coefficient a for regression over the period 1990 to 1999 is 0.78. The Russian Federation has an absolute emission target under the Kyoto Protocol, which it is likely to overachieve by far due to the economic decline. For the purpose of illustrating the effect of intensity targets during economic decline, we describe in two cases what would have happened, if the former USSR would have committed to an intensity target in 1990 that aimed at basically replicating the past trend.

As a first option, a target could be defined as a 1% decrease in GHG intensity per year as of 1990, as it has decreased between 1971 to 1990 (solid circles in Figure 2, fight). Taking the real GDP of the period 1990 to 1999, one calculates that the allowed absolute emissions under this target (solid triangles) would have been well below the actual emissions. For the case of economic decline, such target would have been very stringent and not met by the country, although absolute emissions declined considerably. As a second option, it could be assumed that the relation between emissions and GDP would stay constant and a target could be defined as E = c . G D P °87 , based on the regression 1971 to 1990. Taking the real GDP of the period 1990 to 1999, one calculates that the allowed absolute emissions under this target (open triangles) would have matched the actual emissions better than the first target. USA: The emission intensity of the USA declined from 1990 to 1999 on average by 1.7% per year (Figure 3, left). Regression to the simple relationship yields in a coefficient a = 0.45. Here the coefficient a describes the constant change. The emissions and GDP however show parallel fluctuations, we here also assume another function for the regression. Based on the idea that the GDP increases at an average rate (b) and any additional increase above (or below) that rate will increase (decrease) emissions with an elasticity el, we assume the following relationship and perform a regression: E ( t ) = c . e -b'a't . G D P ( t ) a

(5)

Using this formula from 1985 to 1999, we find that emissions increase on average by 1.3% (=ba) and the GDP has an additional influence with a = 0.88. Changes in GDP above or below the trend by 1%, change emissions with by 0.88%. This coefficient a can be interpreted as the elasticity needed for the intensity target.

1148 It may be noted such regression to emissions of all greenhouse gases, including emissions from forestry (not as in the previous case only CO2 emissions from fuel combustion) does not produce significant results. The is an indication the emissions of the other greenhouse gases are less directly correlated to GDP. 10000

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Figure 3" Emissions, GDP and intensity (Emissions/GDP) for the USA (left) and UK (right) United Kingdom: From 1971 to 1999, the UK reduced emissions while increasing GDP (Figure 3, fight). Regression to the formula Eqn. 5 did not yield significant results. The fluctuation in the GDP does not lead to parallel fluctuations in the emissions. The elasticity could not be obtained from regression of this data.

C O M P A R I S O N OF THE TWO TYPES OF TARGETS In this section, the characteristics of the two approaches are discussed comparatively. The discussion is summarized in Table 1.

Certainty to achieve an environmental goal: Under intensity targets, the total amount of emissions in the target year is not fixed beforehand, it can only be predicted as a range since it depends on the GDP know only after the target year. Under absolute targets, the total amount is fixed and, assuming that the target will be reached, the environmental benefits in terms of emissions are known. Uncertainty of the expected deficit or surplus: Several authors [5,6] mention as a main advantage of intensity targets, that it is more certain than under absolute targets whether the target will be reached or not. This question is analyzed in the following: Let us assume in the target year the emissions depend on the GDP with an elasticity of 0.8. An absolute target, an intensity target with el =1 and an intensity target with el=0.8 are defined for a country and actual emissions are very close to reaching those targets. But an unexpected additional change in GDP of 1% changes the emissions by 0.8%. • Under the absolute target, the allowed emissions would not have changed, real emissions would be 0.8% above the target. • Under an intensity target with el--I, the allowed emissions would now be 1% higher, the real emissions only 0.8% higher: real emissions would be 0.2% below the target. (Note that in such case unexpected growth makes the target easier, while unexpected economic decline would make the target more difficult.) • Under an intensity target with el=0.8, the allowed emissions would now be only 0.8% higher, as would be the real emissions: real emissions would be fight on target. We conclude that the uncertainty of the absolute surplus or deficit in emissions is dependant on elasticity between emissions and GDP. An intensity target with the el =1 provides an advantage over an absolute target,

1149 if the actual elasticity is larger than 0.5, which is assumed to generally be the case. An intensity target with the elasticity set at the actual level would provide even more certainty about the deficit or surplus.

Economic growth: Many countries, especially developing countries, will only accept emission limitation targets, if these do not harm opportunities for economic growth. Absolute targets are often seen as capping emissions and therefore capping economic growth, even if the level of the absolute target is above the current level. Absolute targets can also become a high economic burden, if the emissions increase more than expected or can create "hot air", if they are too loose. Intensity targets are perceived as providing this flexibility and allowing for more emissions if the economy is growing faster than expected. Almost unconstrained economic development can be pursued under an intensity target that is close to the business-as-usual GHG intensity development. If, however, significant reductions in the GHG intensity below business-as-usual are required, an intensity target can be equally restraining as an absolute target. An intensity target is only more flexible if unexpected economic developments occur. As shown in the previous section, average annual changes in GHG intensity differ substantially between countries. Setting percentage reductions in GHG intensity are equal for a group o f countries would advantage those countries with higher economic growth. Intensity targets would therefore be applied differentiated for countries.

Technical requirements: For absolute targets, emissions have to be calculated, usually by collecting activity data and emission factors. The emission calculations have to be reviewed. For intensity targets, the GDP has to be calculated in addition to the emissions. Doubt are often mentioned regarding the non-ambiguous calculation of the GDP: It could be expressed in local currency, based on exchange rates or on purchase power parities; for many developing countries, the GDP does not cover the informal sector; for centrally planned economies, the GDP growth rates are sometimes challenged as being overestimated. However, whether the GDP is calculated in local currency, based on exchange rates or on purchase power parities is only relevant if drastic changes occur (like a crash of one currency used) or a target of one country is compared to that of another. Further, the International Monetary Fund has established rules and review procedures for the calculation of the GDP TABLE 1 PROS AND CONSOF DIFFERENTTYPESOF TARGETS

Absolute tarl~ets

Intensity, tarl]ets

Pro

• Total emissions fixed • Limited number of decisions in setting the target • Target of this type have been agreed under the Kyoto Protocol

Con

• Rigid, if economy and emissions develop unexpectedly leading to 'hot air' or high burden

• Provide flexibility, if GDP higher than expected • Can prevent hot air in case of economic decline • Prediction more certain than for absolute emissions, if emissions and GDP well correlated • Total emissions not fixed • Further data requirement (GDP), acquisition and review • Relationship between emissions and GDP need to be known to set target • More separate decisions in setting the target

• Stringency depends on many factors

• Stringency depends on more factors than for absolute targets • Stringency difficult to compare between countries

1150

Negotiations: In an intemational process, the emissions limitation or reduction targets for different countries have to be negotiated and agreed by all participating countries. For absolute targets, equal percentage reductions could be applied to all countries (one decision), or they could be of different stringency for different countries (n decisions, n = number of participating countries). The negotiation of the reduction values is difficult, but still relatively simple, because only one number per country has to be agreed. The judgement of this one number is relatively difficult, because many variables influence the total absolute emissions (all activity data and all emission factors). Countries have already negotiated such targets for the Kyoto Protocol. Intensity targets would always have to be differentiated, since the relationship between emission and GDP will be different in all countries. The differentiated intensity targets may be more difficult to negotiate than differentiated absolute targets, since a reduction and an elasticity has to be agreed (2n decisions). The judgement of the target involves also an explicit judgement of the relationship between emissions and GDP. More variables influence the emission intensity (all activity data, all emission factors and also the activity in emission extensive sectors). This makes it more difficult to agree on intensity targets than on absolute targets.

CONCLUSIONS We considered two ways to formulate emission limitation or reduction target: absolute targets and intensity targets. We conclude that intensity targets can provide several advantages over absolute targets: They can lead to more certainty whether a target will be reached and they can account for unexpected economic changes upwards and downwards. This is however only possible if emissions and GDP are well correlated, the strength of this correlation is know and used to set the target. If the intensity targets are set assuming a stricter link between emissions and GDP as it actually occurs, unexpected growth makes the target easier, while unexpected economic decline makes the target more difficult. For a limited number of examples we have shown that deriving the relationship between emissions and GDP from historical data as needed for defining intensity targets is difficult for most of these cases. The considered countries were in different phases of development and the relation between emissions and GDP was not always apparent. Further analysis is necessary in order to be able set intensity targets in a way that maximises their advantages over absolute targets.

REFERENCES US government (2002), A new U.S. Climate Change Strategy: A New Approach, available at http ://www.whitehouse.gov/news/releases/2OO2/O2/climatechange.html Argentine government (1999), Revision offirst national communication according to the UNFCCC, available at http://unfccc.int/resource/docs/natc/argnc 1e.pdf Grubb, M.J., C. Hope, R. Fourquet (2002), Climatic implications of the Kyoto Protocol: the contribution of international spillover. Climatic Change 54, 11-28 International Energy Agency (2001), C02 emissions from fuel combustion (2001 Edition). ISBN: 9264-08745-1 Baumert, K.A., R. Bhandari, and N. Kete, (1999) What might a developing country climate commitment look like? World Resources Institute, Climate Note, ISBN: 1-56973-407-0 Philibert, C. and Pershing, J. (2001), Considering the Options: Climate Targets for All Countries. Climate Policy 1, 211-227.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Crown Copyright © 2003 Published by Elsevier Science Ltd. All rights reserved

1151

CANADIAN INITIATIVES ON CO2 CAPTURE AND STORAGE: TOWARDS ZERO EMISSIONS FROM FOSSIL FUELS Kelly Thambimuthul, Gilles Mercier I, Malcolm Wilson 2, Bob Mitchell 3 and Mahmuda Ali 3 1Natural Resources Canada, Ottawa, Ontario, Canada 2 University of Regina, Regina, Saskatchewan 3 Alberta Environment, Edmonton, Alberta ABSTRACT The capture, geological storage and/or utilization of CO2 represent an attractive option to reduce greenhouse gas emissions in Canada. With CO2 capture, co-incidental benefits arising from the removal of a number of secondary air pollutants generated from the utilization of fossil fuels provide additional opportunities to address a number of associated air pollution control issues. As a result, a number of Canadian federal, provincial government and industry-supported initiatives are currently underway aimed at achieving these goals. This paper describes several projects that have been undertaken to characterize the CO2 storage potential geological sinks and for the development and deployment of storage/utilization and capture technologies for achieving near zero emissions of CO2 and other atmospheric pollutants from fossil fuel use. INTRODUCTION

There has been interest in the implementation of components of zero emissions technology (CO2 capture, storage and utilization) for some time in Canada. At the first conference organized by the IEA Greenhouse Gas Programme on CO2 capture and storage in Oxford, UK in 1993, Canadians gave papers on, among other topics, amine capture, membrane separation and mineral carbonate formation in geological media. Canadian activities prior to that time included pilot projects on CO2 enhanced oil recovery. A western Canadian information network was also in operation, bringing together interested players and exchanging information on various aspects CO2 capture, storage and utilization technologies. Since negotiation of the 1997 Kyoto Protocol, Canada has been working diligently towards its ratification. The target is to reduce annual greenhouse gas emissions to a level of minus 6% by 2008-2012 relative to the 1990 level, which is estimated to have been the equivalent of 601 Mt of CO2. In early 1998, the Canadian federal, provincial and territorial ministers of energy and environment initiated work on a national climate change strategy with a mandate to develop a plan to meet the Kyoto target. This in turn prompted the formation of a national initiative on CO2 capture and storage at a meeting held in Regina in March 1998, with subsequent gatherings held in Calgary, Halifax and once again in Regina. The federal government provided further recognition of the importance of emissions reducing potential of capture and storage technologies in October 2000 in its National Implementation Strategy on Climate Change adopted by ministers. This strategy will be implemented through a series of 3 annual business plans or Climate Change Action Plans, the first of which started in 2001. Areas of focus of Canadian initiatives under the 2001 Climate Change Action Plan include: technology development and cost reduction of CO2 capture using amine separation, oxy-fuel combustion and gasification; CO2 storage with enhanced oil

1152 recovery; enhancement of methane recovery with C02 injection and storage into deep coal beds; recovery of methane hydrates with simultaneous CO2 storage; acid gas re-injection; storage capacity assessments of Canadian coal seams, sedimentary basins, oil and gas reservoirs and oil sands tailings streams. Many of the initiatives underway involve public/private sector partnerships and international collaboration, with several of the projects also being led by the private sector. The various initiatives underway are described below. INITIATIVES ON CO2 CAPTURE TECHNOLOGIES AND PLANT SYSTEMS

Amine Separation -International Test Center for COz Capture The intent of this program of activity undertaken by the International Test Center for CO2 Capture located at the University of Regina in Saskatchewan is to undertake testing of amines and associated process developments for the capture of CO2 from relatively dilute, but large volume sources of CO2 such as coalfired electrical generators, natural gas turbines and commercial boilers. The capabilities of the Center include bench scale work, small-scale pilot testing and pre-commercial testing on a larger pilot facility attached to a slipstream from a coal-fired power generating station at Boundary Dam in Saskatchewan. Current work is evaluating the optimal use of existing amine technologies. Work will soon proceed to the testing of alternative amines or amine mixtures with the ability to improve mass transfer reduce process energy consumption and the associated capital and operating costs. It is anticipated that current research will extend over a 3 to 4 year period. The federal and provincial governments are providing capital funding for the project. A consortium of government and industrial participants contribute to an annual operating budget of $550,000 with more than 50% of these funds coming from industry sources. Oxy-fuel Combustion - CANMET Energy Technology Center, Ottawa CANMET CO2 Consortium: This pre-competitive research consortium led by the CANMET Energy Technology Center in Ottawa and coordinated as an international R&D project by the IEA Greenhouse Programme, is investigating oxy-fuel combustion based CO2 capture methods. Work which began in 1994 with the building of a state of the art pilot plant facility for oxy-fuel combustion is currently in Phase 6 of a work program focused on the development of O2/CO2 recycle combustion strategies for retrofit to existing pulverized coal fired power plants. The core research program is aimed at development of computer simulation of oxy-fuel flames and validation of burner concepts using the purpose built oxy-fuel combustion pilot plant. Integrated, multipollutant capture mechanisms for the removal secondary pollutants, after primary particulate capture in an ESP or bag filter, are being studied in a condensing heat recovery and scrubbing environment using technology supplied by McDermott Technologies Inc, USA. Boiler simulation tools are being developed for use in a HYSYS working environment. Outputs of the program are confidential to participants who fund the program, however several papers describing non-confidential data have been released in the public domain. The consortium's activity is currently supported by the Canadian federal government, Alberta government, US Department of Energy, TransAlta Utilities, Sask Power, Ontario Power Generation, McDermott Technology Inc and Air Products and in the past by EPCOR, Nova Scotia Power and Air Liquide. Oxy-Fuel Field Demonstration Project: This project is aimed at the selection of an optimal 02/C02 recycle combustion method for a natural gas fired industrial scale boiler, the development and demonstration of required burner technology and participation in a field storage experiment led by the Alberta Research Council (see below) to study the use of a variable COz/N2 product stream for enhanced coal bed methane recovery with CO2 storage at a site to be determined in Western Canada. The project is receiving $1.5 million in funding over a period of 5 years from the 2001 Climate Change Action Plan and is currently seeking industrial partners.

Closed Gas Turbine Cycle Project: Performance evaluation of various closed gas turbine cycles utilizing oxy-fuel combustion to produce power and capture CO2. Work program includes simulation activities and primary research at two Canadian universities. Work undertaken with Carleton University in Ottawa is aimed at understanding the

1153 fundamentals of compressor performance when changing the primary working fluid to C02. Funding will also support a project to design and construct a micro-turbine system to study the operation of a closed cycle gas turbine. Work underway with the University of Waterloo is aimed at developing simulations of a solid oxide fuel cell (SOFC) system integrated with a closed cycle gas turbine. The project is receiving $250,000 in funding over a period of 5 years from the 2001 Climate Change Action Plan (CCAP). The Zero Emission Coal Alliance (ZECA)

A US-Canadian consortium, comprised of 18 members representing governments, research organizations and the coal, utility, mining, and equipment manufacturing industries has proposed the development of a novel, highly efficient technology to generate electricity and/or hydrogen from coal with zero atmospheric emissions. Expanding on ideas originally proposed by the Los Alamos National Laboratory in New Mexico, U.S.A., the ZECA concept comprises a coal gasification power plant to produce electricity via a high-temperature solid oxide fuel cell (SOFC) and a mineral carbonation plant to store the CO2. First, coal is gasified to produce hydrogen and CO2. The hydrogen is then used to fuel the SOFC. The CO2 formed is reacted with lime to form calcium carbonate, which is calcined at high temperature using the waste heat from the SOFC and separated into a pure CO2 stream and the original lime. The lime is continuously recycled for CO2 capture from the process stream. The pure CO2 is sent to the mineral carbonation plant and reacted with serpentine or olivine (magnesium silicates) to form magnesium carbonate and silica, which are then returned to the serpentine mine. Magnesium carbonate is benign and thermodynamically stable, thus guaranteeing permanent and safe storage of the COz. ZECA completed a US$716,000 techno-economic feasibility study in November 2001 that did not identify any fatal flaws in the concept and concluded that the gasification power plant technology showed good performance, high overall efficiency (around 70%), with competitive electricity costs relative to other advanced power generation schemes incorporating CO2 capture. Technical and business plans to design, construct and operate a pilot plant within five years are currently being developed. These plans will be presented to shareholders and potential investors in the near future.

Canadian Clean Power Coalition An association of 7 Canadian utilities, coal producers and the US Electric Power Research Institute, the Coalition proposes a program focused on "securing a future for coal-fired electricity generation". Initiatives provide for the development, construction and operation of a full-scale demonstration project by 2007 that will remove GHG and other secondary pollutant emissions of concem from an existing coal fired power plant and a similar demonstration project by 2010 applied to a greenfield coal fired power plant. Implementation is expected to cost around $1 billion. Phase I of the project (conceptual engineering and feasibility studies) worth about $5 million has been underway since September 2001, with secure industrial funding and signed agreements with the provinces of Alberta, Nova Scotia, Saskatchewan and the federal government. Completion of Phase I is planned for mid-2003 with the identification of the technologies to be used in the field demonstrations. Phase II (detailed engineering and construction) is expected to commence in late 2003. Efforts to find funding for Phase II scheduled for completion by 2010 are just commencing. INITIATIVES ON CHARACTERISATION OF THE CAPACITY OF COz STORAGE SINKS

Storage of C02 Canada's Sedimentary Basins Sedimentary basins have various degrees of suitability for CO2 storage in geological media as a result of different conditions and geological, hydrostatic and thermal characteristics. The purpose of the project is to identify on a continental scale the suitability of approximately 70 sedimentary basins in Canada for CO2 storage in geological media. On a regional scale, the suitability for CO2 sequestration of the Alberta basin and of the Canadian part of the Williston basin (shared with the US) is being assessed both geographically

1154 and stratigraphically. At the present time this project led by the Alberta Energy and Utilities Board (AEUB) has completed studies on the Alberta basin with expected completion of the Canadian part of the Williston basin in December 2002. Project funding of $270,000 from the federal and Alberta government, the latter from the AEUB.

Storage of C02 in Alberta's Oil and Gas Reservoirs Alberta currently has approximately 26,000 gas pools and more than 8,500 oil pools in various stages of production and depletion. The ultimate capacity for CO2 sequestration in these pools has been estimated using the Alberta Energy and Utilities Board reserves database. Results to date indicate that the ultimate CO2-storage capacity in Alberta's gas reservoirs not associated with oil pools is 9.8 Gt CO2. The storage capacity in the gas cap of approximately 5,000 oil reservoirs is 2.2 Gt COa. In contrast, the storage capacity in depleted oil pools is only 637 Mt CO2. Of the more than 8,500 oil pools in Alberta, 4,273 reservoirs were identified as suitable for CO2-flood EOR. Estimates of the incremental CO2-storage capacity in these reservoirs at CO2 breakthrough and at 25 and 50% hydrocarbon pore volume (HCPV) of injected CO2 indicate that an additional 117, 360 or 673 Mt CO2, respectively, would be stored through CO2-flood EOR. The objective of the last stage of the project is to develop and apply reservoir ranking methodology that will consider such elements as reservoir characteristics, CO2 capacity, injectivity, depth, distance from CO2 sources and timing, in order to identify the hydrocarbon reservoirs that should be considered first in the implementation of large-scale CO2 sequestration in oil and gas reservoirs in Alberta. The project led by the Alberta Energy and Utilities Board (AUEB) commenced in 2000 with expected completion in March 2003. Project funding of $240,000 from the Alberta Energy Research Institute coveting operating expenditures and more than $300,000 worth of manpower resources provided by AUEB.

COz storage capacity of deep coal seams in the vicinity of large C02 point sources This project aims to utilize the many oil and gas well intersections of deep coal seams in Alberta in the vicinity of large CO2 point sources to determine the distribution, thickness and depth of deep coals and to determine reservoir properties including pressure and temperature and through experimentally derived CO2 adsorption isotherms to assess the in place storage capacity of CO2 expressed as Mt/km 2. The work undertaken by the Geological Survey of Canada has continued intermittently since 1997 with current funding at $275,000. Ongoing work to be completed in 2003 is funded by the 2001 Climate Change Action Plan. Work funded by the Canadian Clean Power Coalition, Nova Scotia and the federal government will also assess the CO2 storage capacity of deep coal seams in Nova Scotia. INITIATIVES ON CO2 STORAGE AND UTILIZATION

lEA Weyburn COz Monitoring and Storage Project The primary objective of the project is to understand geo-sequestration of GHG, particularly CO2 piggybacking on the EnCana Corporation's CO2 miscible flood project at the Weyburn oil reservoir located in southern Saskatchewan. The scope of work includes understanding mechanisms of storage and the degree to which CO2 can be permanently retained in geological formations. The technology and know-how thus obtained can then be applied in selecting appropriate CO2 storage sites and in designing and implementing successful CO2 storage projects worldwide. The ultimate deliverable is a credible assessment of the permanent containment of injected CO2 as determined by long-term predictive simulations and formal risk analysis techniques. This 4 year project managed by the Petroleum Technology Research Center in Regina and coordinated as an international demonstration project by the lEA Greenhouse Gas Programme, receives total cash funding of $20.5 million and additional in-kind contributions valued at approximately an equal amount. Funding participants include the following organizations - Natural Resources Canada, Saskatchewan Energy and

1155 Mines, Government of Alberta, US Department of Energy, European Community, EnCana, Sask Power, Nexen Canada Limited, BP, Dakota Gasification Co, TransAlta Utilities, E N A A - Japan and TotalFinaElf. Enhanced Coal Bed Methane Recovery f o r Zero Greenhouse Gas Emissions

Supported by the IEA Greenhouse Gas Programme as an international demonstration project and led by the Alberta Research Council, this Canadian project is looking at the commercial viability of coal bed methane (CBM) in Alberta through enhancement of CBM recovery factors and production rates in low permeability CBM reservoirs by injection of CO2-rich waste streams; and reducing greenhouse gas emissions by subsurface injection (and storage) of CO2 into coal beds with added value from production of CBM. Phase I of the Canadian project was the initial assessment and feasibility of injecting pure CO2 into deep Mannville coals. Phase II was the design and implementation of a micro-pilot test for injection of pure COz in an existing CBM well located at Fenn-Big Valley in Alberta following Amoco Production Company procedures. Phase III was the assessment of reservoir response to different compositions of injected flue gases and the design and implementation of a multi-well pilot project. Phase IV is the matching of novel combustion and separation technologies to produce a CO2 waste stream with CBM reservoirs to carry out additional multi-well ECBM pilot tests. To date, all testing undertaken in Phases I-III has been successful and the economics of the process is being accessed. It is expected that the final results will show gas producers the best way to enhance production from low permeability CBM wells. On the other hand, reducing greenhouse gas emissions is a priority to the utilities and is addressed. Cost curves will be generated to assess the price per tonne of CO2 stored in coal reservoirs based on a wellhead price of natural gas and composition of flue gas injected. Current funding participants include Environment Canada, Canadian Climate Change Action Plan, Geological Survey of Canada, Alberta Innovation and Science, Alberta Geological Survey, Saskatchewan Energy and Mines, US Department of Energy, UK Department of Trade and Industry, Netherlands TNO, Japan Coal, CSIRO Australia, Gas Technology Institute, Suncor Energy, BP, Burlington Resources, Conoco Canada, EnCana Corporation, MGV Energy Inc., ExxonMobil Canada, Husky Energy, PetroCanada, TransCanada Pipelines, EPCOR Utilities, TransAlta Utilities, Air Liquide, Sproule International, Tesseract, University of Alberta, University of British Columbia and BJ Services Canada. The project started in 1997 and is expected to end in 2005. To date more than $4 million Canadian has been expended on the project. Acid Gas Re-injection in Alberta, Canada

At the end of 2001 there were 31 sites in Alberta where acid gas was re-injected into depleted oil and gas reservoirs and deep saline aquifers primarily as a safe method of disposal of waste HaS streams. The composition of the re-injected gas varies from 20% COz and 80% H2S to 95% CO2 and 5% H2S. These acid gas injection operations in Alberta represent an analogue for geological sequestration of CO2. Thus, the study of the acid gas injection operations provides the opportunity to learn about the safety of these operations and about the fate of the injected gases, and represents a unique opportunity to investigate the feasibility of CO2 geological storage. The Alberta Geological Survey (AGS) of the Alberta Energy and Utilities Board (AEUB) and the Alberta Research Council (ARC) are jointly carrying out a project to review the information submitted by operators to EUB in the process of obtaining approval for and running these 31 acid gas injection operations. AGS is reviewing the subsurface characteristics and ARC is reviewing the surface facility characteristics of these operations. One of these sites will be selected and undergo a comprehensive due diligence to establish the viability and importance of this technology for creating greenhouse gas emission credits when a trading market is firmly established The initial assessment project will run from December 2001 to October 2002 with $ 205,000 in funding from Canadian federal and provincial governments, other government agencies and the IEA Greenhouse Gas Programme.

1156 Sequestration of Carbon Dioxide in Oil Sands TaUings Streams The availability of high purity carbon dioxide (from hydrogen production) at oil sands refineries is an opportunity to use this refinery waste stream to favorably manipulate the properties of the oil sands extraction tailings waste stream. The chemistry of the oil sands tailings stream is such that the physical, ionic and mineral sequestration of CO2 can be promoted. This work will establish the limits to these three mechanisms of sequestration and define the possible operating conditions and benefits leading to a pilot demonstration of what would be a completely new technology. The project led by the CANMET Energy Technology Center- Devon receives $1 million in funding over a period of 5 years from the 2001 Climate Change Action Plan. Industry and provincial interest is being solicited. Suncor has contributed some funds in the past and has agreed to provide up to $50,000 in kind support for 2002.

Simultaneous Geological C02 Sequestration/CH4production from natural gas hydrate reservoirs This research project led by the Geological Survey of Canada, addresses the feasibility of geologic sequestration of CO2 as a hydrate and the possibility of coincident CO2 sequestration/CH 4 production from natural gas hydrate reservoirs such as those occurring offshore of Canada's coasts or in the Arctic. New laboratory investigations will establish the fundamental geologic controls (physical and geochemical) on CO2 hydrate formation and stability in porous media. Assessments of the suitability of candidate marine, lacustrine and Arctic reservoirs will be undertaken using existing geologic data and new field data acquired in conjunction with the Mallik 2002 International Gas Hydrate Production Research Well (also led by the Geological Survey of Canada). Linkages to the Mallik program will contribute substantially to the understanding of the physical, geochemical, geothermal and permeability characteristics of an actual gas hydrate reservoir. Funding of $307,000 by the 2001 Climate Change Action Plan over a period of 4 years. CONCLUSIONS Significant R&D activity is underway in Canada aimed at the development of CO2 capture, storage and utilization technologies that could achieve near zero emissions of greenhouse gas and other atmospheric pollutants from fossil energy use. Assessments of the storage capacity of CO2 in geological media indicate that a significant quantity of CO2 can be sequestered in sedimentary basins, the most significant of those evaluated that occur in the provinces of Alberta and Saskatchewan. The serendipitous co-location of geological storage sinks in regions of oil, gas and coal-mining activity in the western Canadian sedimentary basin also provides some synergistic opportunities in matching sources and sinks for greenhouse gas emissions from fossil fuel use with some commercial benefits that can be gained from CO2 utilization in enhanced oil and coal bed methane recovery operations. Canadian initiatives on the development of more cost efficient methods of CO2 capture from fossil fueled processes are primarily focused on the development of improved amine and oxy-fuel combustion based systems but with work also underway on coal gasification based capture technologies. There is a significant degree of public and private sector cooperation in Canada for the development and deployment of CO2 capture, storage and utilization technologies to address global climate change, with several of these initiatives also soliciting the active engagement of other international participants. ACKNOWLEDGEMENTS The authors gratefully acknowledge the contributions of various project leaders who provided descriptions of their individual projects listed in this paper and as a part of activities coordinated by the Canadian CO2 Capture and Storage Technology Network (CCCSTN). CCCSTN also gratefully acknowledges funding received under the Government of Canada's 2001 Climate Change Action Plan.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Crown Copyright © 2003 Published by Elsevier Science Ltd. All rights reserved

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AUSTRALIA'S RENEWABLE ENERGY CERTIFICATE SYSTEM David Rossiter and Karla Wass Regulator and Manager, Office of the Renewable Energy Regulator Kings Avenue, Barton ACT 2600, Australia GPO Box 621, Canberra ACT 2601, Australia Tel: 61 2 6274 1436, Fax: 61 2 6274 1725

ABSTRACT Concern about climate change and concerted international action to reduce greenhouse gas emissions are powerful new drivers for renewable energy. Australia has developed a national tradeable renewable energy certificate system to encourage additional renewable energy in electricity supplies. The paper outlines the objectives of the Renewable Energy (Electricity) Act, its legal framework, describes the tradeable certificate mechanism and summarises the experience of the first year (2001) of operation of the Act.

AUSTRALIA'S R E N E W A B L E ENERGY C E R T I F I C A T E SYSTEM B A C K G R O U N D AND INTRODUCTION

On 20 November 1997 the Prime Minister of Australia in his statement "Safeguarding the Future." Australia's Response to Climate Change" committed to working "with States and Territories to set a mandatory target for electricity retailers to source an additional two percent of their electricity from renewable sources by 2010." The measure became known as the Mandatory Renewable Energy Target (MRET). This paper outlines the objectives of the Renewable Energy (Electricity) Act, its legal framework, describes the tradeable certificate mechanism and summarises the experience of the first year of operation of the Act.

OBJECTIVES AND OUTLINE OF ACT There are three objectives stated within the Act. They are: • encourage the additional generation of electricity from renewable energy sources; • reduce greenhouse gas emissions; and • ensure energy sources are ecologically sustainable. The Act sets up a liability for persons making certain acquisitions of electricity. Liable acquisitions are typically those purchases o f electricity by large buyers who did not generate the electricity

1158 themselves, for example electricity retailers. Liable entities are required to discharge their liability by surrendering Renewable Energy Certificates to the Regulator or pay a shortfall charge. This creates a demand for certificates and provides one side of the market. Renewable energy certificates can only be created by eligible accredited renewable energy generators. This creates the supply side of the market. Through the market liable entities can trade directly or indirectly with certificate producers to acquire certificates to meet their liability. Large buyers of electricity such as wholesale purchasers and retailers are collectively required to source an additional 9500 GWh of their electricity from renewable energy sources by 2010 relative to 1997. This takes Australia from around 16,000 GWh per annum of renewable energy in electricity in 1997 to about 25,500 GWh per annum (over 11% of total) in 2010, or an increase of about 60% in that period. The rate of liability is set annually in regulations to achieve the targets set for each year. TABLE 1 ANNUAL ADDITIONAL RENEWABLE ENERGY TARGETS FOR ELECTRICITY SUPPLIES RENEWABLE ENERGY TARGET (MWH)

Year

Renewable Energy Target (MWh)

Year

Renewable Energy Target (MWh)

2001 2002 2003 2004 2005

300,000 2006 4,500,000 1,100,000 2007 5,600,000 1,800,000 2008 6,800,000 2,600,000 2009 8,100,000 3,400,000 2010 - 2020 9,500,000 Note: Target for 2001 is for nine month period from 1 April 2001 to 31 December2001. All other targets are for full calender years.

Legal framework The mandatory renewable energy target is implemented through two Acts. They are the Renewable Energy (Electricity) Act 2000 and the Renewable Energy (Electricity) Charge Act 2000. The former Act details the requirements and provisions to enable the liability and certificate system to operate and the latter Act sets the penalty of A$40/MWh for shortfalls in certificate surrender. Both Acts are available at www.orer.gov.au.

Tradeable certificates Renewable energy certificates can only be created by registered persons generating electricity above their 1997 baseline. Generally, these persons have to register under the Act, apply for accreditation and successfully achieve accreditation before they are eligible to create certificates. However for solar water heaters and small generation units (under 10kW and under 25 MWh per year) registered persons can be deemed to be eligible for a fixed number of certificates for certain types of equipment. Upon accreditation eligible renewable energy generators that have exceeded their baseline may enter an internet-based registry and create certificates any time after they have generated the additional electricity.

1159

Experience offirst year's operation The Act started full operation on 1 April 2001. The following sections describe the first year of operation from 1 April 2001 to 31 December 2001. Registration and Accreditation In 2001, the ORER received 126 applications for registration as a registered legislation. Applications for accreditation of a power station must be made by a Both of these actions attract fees - A$20 for registration and a sliding scale fee for accreditation depending on the size and complexity of the power plant. The vary from A$20 to A$3,000.

person under the registered person. for an application accreditation fees

In 2001 the ORER received 152 applications for accreditation of power stations. The majority of these applications were received prior to the 1 April 2001 start date, although applications continued to be submitted throughout the year. Table 2 shows the status of the 152 applications at the end of 2001. TABLE 2 STATUS OF APPLICATIONS FOR ACCREDITATION AT END OF 2001 STATUS OF APPLICATION Accredited Pending accreditation (still being processed) Rejected* Withdrawn Awaiting payment of fees Total number of applications for 2001 *Rejected includes applications that were combined with other applications.

NUMBER OF APPLICATIONS 126 19 1 3 152

Table 3 lists the eligible renewable energy sources and the number of accreditations for each source. Small Generators and Solar Water Heaters In order to encourage participation of small generators using hydro, wind or photovoltaics, where the system is less than 10kW capacity and producing under twenty five certificates per year, and some solar water heater installations, these types of systems are eligible for deemed numbers of renewable energy certificates. Certificates for these systems can be assigned to an agent who may act on the owner's behalf to reduce the net transaction time and costs. Renewable Energy Certificates Created As at 17 July 2002, 794,562 certificates had been created and registered for 2001 generation. Table 3 lists the eligible renewable energy sources from which the certificates were created. Surrender of Certificates For 2001 a target is stipulated in the legislation of 300,000 certificates. The Regulator received 314,863 certificates for 2001 liabilities (see Table 3) although not all of these were accepted. While more than 300,000 certificates were surrendered, the legislation allows adjustment of the renewable power percentage in future years to take account of any 'overs' and 'unders' in the target achievement.

1160

TABLE 3 ACCREDITATION AND CERTIFICATE STATUS R.E. Source

No. Accreditations*

Hydro Solar Landfill gas Wind Bagasse Sewage Gas Wood waste Black liquor Food and agricultural waste Municipal solid waste Solar water heaters Small generation units Totals:

56 23 19 10

1 N/A N/A 126

No. Certificates Created 293,876 528 86,538 95,017 57,791 9,292 36,740 14,631 -

No. Certificates Surrendered** 154,746 38,912 49,676 1,052 17,587 7,785 -

200,112 37 794,562

45,105 314,863

*Three landfill gas projects were combined with other landfill gas applications. *Wood waste projects used cofu'ingtechnology. *Some projects were hybrid i.e. wind/solar- they have been counted only under the dominant eligible renewable energy source. ** As of 15 February2002.

DISCUSSION This has been the first year of operation of the first national renewable energy certificate trading scheme in the world. Preliminary analysis of the year's performance indicates that the scheme is operating well and compliance is being achieved. Several issues have arisen during the year. Of particular interest is the baseline issue, as it shows the level of detail that needs to sit behind the framework legislation at all levels for it to function effectively. Baselines

Baselines are required for all power plants under the legislation but they are typically zero for all power plants that first generated electricity after 31 December 1996. Less than half the power plants accredited for 2001 had zero baselines. Baselines were calculated mainly for hydro, landfill gas and bagasse (sugar mill waste) power plants, which reflects historic renewable energy supply in Australia. The most complex processes were for setting baselines for hydro power plants and bagasse power plants due to the inherent variability of their renewable energy sources. A sugar mill is a good example of how a baseline is derived. The methodology used was negotiated at workshops with the industry and with independent technical consultants. The methodology takes into account the annual variability of sugar cane harvest area, crop, yield and fibre content to establish the sugar mill production for a typical 1997 year configured as it was at that time. Additionally, auxiliary loads are apportioned between electricity generation plant and sugar processing equipment.

1161

EXPECTED INVESTMENT The total expected investment in renewable energy over the twenty year life of the measure is about A$6 billion. Due to the nature of investments needed to create renewable energy certificates it is anticipated that investors will tend to enter the market in the first five or so years of the measure. This will enable investors to amortise these investments over more than ten years. At this early stage it is difficult to estimate how much investment has been triggered by the Act since projects often proceed for multiple reasons. However approximately $200 million of investment appears to have already occurred and over $600 million further investment appears to be firmly committed. Many other project proposals have also been mooted representing considerably more investment but not all can proceed. For example one State alone has enough wind farm prospects to exceed the target for 2010 though not all projects could proceed without major power system stability issues arising.

TRADING IN THE M A R K E T Though many projects have forward sold their output of RECs some spot market activity has occurred. As early December approached the very limited spot market showed prices were rising and thus tended to stimulate the wider production of RECs. Spot prices in the range of $32 to $36.50 MWh have been reported by third parties for the 2001 period. But most RECs appear to be bought and sold under forward agreements and price disclosure is not normally available on these trades. However it is generally believed these forward trade prices are lower than spot.

CONCLUSIONS The Renewable Energy (Electricity) Act 2000 is operating well with over 150 accredited power plants by mid-2002 and many small generation units contributing towards the operation of the measure. For the year 2001 the certificate target was 300,000 MWh of additional renewable energy and over 790,000 MWh appears to have been generated and claimed to date. The surrender of over 314,000 MWh of those renewable energy certificates for the year bodes well for the achievement of the Act. The tradeable renewable energy certificate approach used in the Act is novel in Australia and internationally as a mandated national target. The Act represents a major change in how additional renewable energy electricity generation is valued in Australia. The industry has responded rapidly and effectively to this change and appears to be well positioned to assist Australia in meeting this greenhouse emission reduction measure.

REFERENCES 1. Office of the Renewable Energy Regulator Website www.orer.gov.au 2. Renewable Energy Certificate Registry Website www.rec-registry.com 3. Renewables Target Working Group (1999) Final Report to the Greenhouse Energy Group:

Implementation Planning for Mandatory Targetfor the Uptake of Renewable Energy in Power Supplies May 1999. Australian Greenhouse Office, Canberra.

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1163

F I N A N C I A L INCENTIVES FOR C L I M A T E N E U T R A L E N E R G Y CARRIERS Chris Hendriks, 1 Mirjam Harmelink, 1 and Rob Cuelenaere 2 ! Ecofys Energy and Environment, P.O. Box 8408, NL-3503 RK Utrecht, Netherlands, [email protected] 2 Ministry of Housing, Spatial Planning and Environment, The Hague, Netherlands

ABSTRACT The Dutch government is currently examining the possibilities to promote the production and use of climate neutral energy carriers. Climate neutral energy carriers are energy carriers from fossil fuels with a low level of associated emissions of greenhouse gases. To judge whether a project qualifies for financial support understanding must be obtained on additional costs and avoided emissions. A conceptual framework is developed and applied to five different case studies for the production and use of climate neutral energy carriers. When taking the whole lifecycle of the energy carrier into account, the emission of the production and use of climate neutral hydrogen varies per project and ranges from 17 to 33 kg of carbon dioxide equivalent per gigajoule. The emission factor for climate neutral electricity for the examined projects amounts to 0.2 to 0.5 kg per kWh.

INTRODUCTION Climate neutral energy carriers are defined as hydrogen and electricity produced by means of fossil fuels and by which (a substantial part of) the produced carbon dioxide is stored or put to good use. The term "climate neutrality" of an energy carrier refers to the share of the energy cartier that can be marked as climate neutral. To judge whether a project qualifies for financial support the climate neutrality needs to be taken into account. All changes in the emissions of greenhouse gases in the production chain should therefore be determined. The emissions of production and application of an energy neutral energy carrier are compared to the emissions in a reference system. The results of the study are used to develop a calculation methodology which should be used for project developers to submit an application for financial support. In addition, the production costs of climate neutral hydrogen and electricity are compared to the current prices of natural gas and electricity for small consumers.

STARTING CONDITIONS C L I M A T E NEUTRAL ENERGY C A R R I E R S The production and application of climate neutral energy carriers should fulfil a number of conditions in order to qualify for possible financial support: • the climate neutral energy carriers should be produced from fossil energy carriers in addition to which the carbon dioxide is stored or put to good use, • the produced climate neutral energy carriers should be electricity or hydrogen, and • the reduction of carbon dioxide emissions may not be used to fulfil existing obligations or agreements.

1164 It was expected that production technologies and application of climate neutral energy carriers might considerably differ in terms of greenhouse gas emissions and (additional) costs compared to fossil fuel energy carriers. To examine these variations systematically, we introduce two concepts: the system boundaries and the reference system. At the hand of five case studies the climate neutrality and additional costs are assessed. In this study we restrict the system boundaries to seven different elements which form the total chain of production and application of (climate neutral) energy carriers. The different chain elements are displayed in Figure 1. The production chain includes: 1. Extraction and production of the fossil energy carrier. 2. Transport of the fossil energy carrier. 3a. Production of the climate neutral energy carrier (e.g. hydrogen or electricity) and CO2 or carbon. 3b Compression of the CO2. 4. Transport and/or distribution of the CO2 or carbon. 5. Storage of the CO2 or carbon. In this step the CO2 is stored or put to good use. 6. Transport and distribution of the climate neutral energy cartier. 7. End-use of the climate neutral energy carrier. This means the use of the climate neutral energy cartier by the end-user.

4

!

1

''

2

3a

' ' r°duti°n°fH

production ~ . Transport . ~ climateneutral fossil energy carried- If°ssd energy came1 I energycarrier & CO2/carbon

II

II

3b Compressionof CO2

Transport CO2/carbon

5 [~Storage or good useI I I CO2/carbon ]

6 Distribution H climate neutral energy carrier

7 End-use climate neutral energy carrier

Figure 1: Chain e l e m e n t s in a p r o d u c t i o n chain for c l i m a t e n e u t r a l e n e r g y carriers The 'reference system' is defined as the amount of greenhouse gases that would have been emitted and the costs that would have been made in the absence of the project. The reduction of greenhouse gas emissions and additional costs due to the implementation of a production chain can be calculated by comparing the emission and costs of the production chain with the emission and costs in the reference system. In principle two different approaches can be applied to determine the emissions and costs in the reference systems. 1. In the multi-project approach generic emissions factors and cost figures for a certain activity are used to calculate the emission and generated costs in the reference systems. These generic emission and cost factors are project independent and can e.g. be derived from benchmarks. 2. In the project specific approach the emissions and costs in the reference system are calculated with project specific assumptions or measurements for all important project parameters. E.g. emission factors of one specific electricity production plant are used because it can be argued that the project replaces electricity generated by that specific plant.

Applying different approaches For the production of climate neutral electricity by means of a coal-fired power plant and storage of the CO2 in empty gas fields roughly three different approaches can be applied to calculate the emissions in the reference system: 1. The electricity generated with the project replaces the average produced electricity in the grid (e.g. the Dutch grid or the European grid);

1165

2. The electricity generated with the project replaces electricity produced by a specific technology mix (e.g. the average public mix, industrial power or a specific technology e.g. a combined cycle unit); 3. The electricity generated by the project replaces electricity generated by a specifically defined plant (e.g. due to the implementation of the project another (specific) power plant is closed down or not erected). When applying the different approaches to a zero emission power plant (i.e. PC3 characterised in TABLE 1) the amount of achieved CO2 emission reduction per kWh is: 0.2 kg CO2-eq per kWh when using the combined cycle as a reference system, 0.4 kg CO2-eq per kWh when using the average production mix in the Netherlands, 0.7 kg CO2-eq/kWh when applying the project specific approach. For the production of climate neutral hydrogen the reference system is defined as the use of natural gas. The emissions in the reference system can be calculated by taking the emissions of greenhouse gases for the production of natural gas in the Netherlands. In this case only a multi-project approach can be applied and the emission reduction per GJ hydrogen ranges from 43 kg CO2-eq/GJ H2 for PC1 to 27 kg CO2-eq /GJ H2 for PC2 (for comparison natural gas has an emission factor of 60 kg CO2-eq/GJ). CASE STUDIES This conceptual framework has been applied to five different case studies, which are listed in TABLE 1. The case studies represent the variation in the different elements in the production for a climate neutral energy carrier. The elements in the case studies were selected on basis of maturity for technology available, and whether it has a substantial emission reduction potential in the Netherlands. TABLE 1 CHARACTERISATION OF FIVE EXAMINED PRODUCTION CHAINS Code

Production facility

Storage/use of C02/Carbon

PC1 NaturalGas Reforming + fuel gas recovery Storage in coal layers by ECBM PC2 Coal gasification+ fuel gas recovery Storage in emptyNG field PC3 Coal combustionwith pure 02 (1) CO2 used in production of methanol C O 2 used in ~reenhouses + storage PC4a Fluegas recoveryof coal-ftredpower plant PC4b Fluegas recoveryof natural fired power plant CO2 used in greenhouses + storage PC5 Naturalprocessing (recoveryof abundant CO2) Storage in aquifer (1) this facilityis based on a zero emissionplant concept which is still in an early stage of development.

Climate neutral Energy carrier

Hydrogen Hydro~:en Electricity Electricity Electricity Natural gas

EXAMPLE O F C A S E STUDY In this paragraph we give a short description on one of the examined case studies. In production chain PC4b annually five petajoule of climate neutral electricity is produced by a conventional gas-fired power plant. The electricity is added to the grid. An amine process separates the carbon dioxide from the flue gases of the power plant. The recovered carbon dioxide is compressed and transported over 100 km. On average 25% of the recovered carbon dioxide is used in greenhouses, the remaining 75% is stored underground in empty natural gas field. In this example it is assumed that the electricity in the project replaces electricity produced by the 'average park' in the Netherlands. In the reference case gas engines locally produce the carbon dioxide for the greenhouses. In periods that carbon dioxide is not required for fertilising or co-incidence with heat demand, the carbon dioxide is stored into an empty natural gas field. TABLE 2 presents the comparison of the emissions in the project and the reference case for each chain element.

1166

TABLE 2 EMISSIONS OF CARBON DIOXIDE (GG/Y) FOR EACH CHAIN ELEMENT FROM THE ANNUAL PRODUCTION OF 5 PJE OF PRODUCTION CHAIN PC4B COMPARED TO EMISSIONS FROM THE REFERENCE CASE (ELECTRICITY FROM "AVERAGE PARK") # 1

2 3a 3b 4 5 6 7

Production chain element Extraction fuel Transport fuel Production energy carrier Compression carbon dioxide Transport carbon dioxide Storage/use carbon dioxide Distribution energy cartier Application energy carrier Total C02-eq emission Emission reduction

Reference 50.1 4.9 609.1 0.0 0.0 157.5 0.0 0.0 822

78%

Project 6.0 21.0 70

Comment Average fuel emissions is higher than for natural gas Gas engine with power efficiency (38%) and heat efficiency (38%) Compression energy: 430 kJe/kg CO2 No recompression required Annual use of CO2 in greenhouses No emissions occur during transport of electricity No emissions occur during use of electricity

46.9 0.0 157.5 0.0 0.0 301 63%

RESULTS Per case study, for each chain element the contribution to the total emission is determined. Figure 2 and Figure 3 show that the climate neutrality o f the energy carriers lies in the range of 7% to 77% (black bars in the figure). The figures show that the largest changes in emissions take place either at the end user (chain element 7) in cases where hydrogen is produced or in the production stage (chain element 3) for projects where electricity is produced.

20% 0%

.o_ -20% .E

(Natural Gas'i,£1~

(Natural Gasi!i!!

(Natural Gas)

-40%

~o

........ ;:~i~: :,)?!i,;)! ::~::::! ~:i!?i~ !~!!i~ ~!+~!~

-60% -80%

PCI: NG reforming and fuel gas recovery + ECBM + H2 in grid PC2: Coal gasification + CO2 in empty NG field + H2 in grid PC5: NG processing and storage of CO2 in aquifer

-100% [] 1 Extraction and production of fos.,il energy carrier [] 3a Production of CNE & CO2/carbon • 4 Transport CO2/carbon • 6 Distribution CNE

• 2 Transport fossil energy carrier [] 3b Compression of CO2 [] 5 Capture and storage/use CO2 [] 7 End-use CNE • Climate neutrality

F i g u r e 2 : C h a n g e s in e m i s s i o n in e a c h o f the c h a i n e l e m e n t s for the h y d r o g e n p r o d u c t i o n c h a i n (the r e f e r e n c e s y s t e m for e a c h p r o d u c t i o n c h a i n is i n c l u d e d in b r a c k e t s )

1167 20%

0%

B

l| PC3 ~,veragePark)

.2 -20%

,

~PC4a

I

gepark+g--engine) (Ar .

-m,A/

....

oE

•-

-40%

-60% PC3: Coalfiredzeroemissionplant+ methanolproduction. Conventionalcoalfiredplant+ CO2 deliveryto greenhouses+ storage PC4b: Naturalgas firedplant+ CO2deliveryto greenhouses+ storage

-80%

PC4a:

-100% [] i Extractionand productionof fossilenergycarrier • 2 Transportfossilenergycarrier [] 3a ProductionofCNE& CO2/carbon [] 3b Compressionof CO2 • 4 TransportCO2/carbon [] 5 Captureand storage/useCO2 • 6 DistributionCNE [] 7 End-useCNE • Climateneutrality Figure

3" C h a n g e s in e m i s s i o n in e a c h o f the c h a i n e l e m e n t s f o r t h e e l e c t r i c i t y p r o d u c t i o n c h a i n ( t h e r e f e r e n c e s y s t e m f o r e a c h p r o d u c t i o n c h a i n is i n c l u d e d in b r a c k e t s )

The main results per case study on costs and climate neutrality o f the energy carder are summarised in T A B L E 3. TABLE 3 S U M M A R Y OF T H E M A I N R E S U L T S F O R THE F I V E E X A M I N E D PRODUCTION CHAINS Code

Emission Factor

Costs a

Reference

PC 1 PC2 PC3 PC4a PC4b PC5

17 kgCO2/GJ Ha 33 kgCO2/GJ H2 0.2 kgCO2/kWh 0.5 kgCO2/kWh 0.2 kgCO2/kWh 59 kgCO2/GJ NG

13.5-16.2 euro/GJ H2 15 euro/GJ H2 0.08 euro/kWh 0.11 euro/kWh 0.09 euro/kWh 6.0 euro/GJ NG

Natural gas Natural gas Average park Average parldgas engineb Average park/gas engineb Natural gas

Climate neutrality c

71% 46% 77% 21% 63%

7% a) 15% discount rate. For comparison: prices for small consumers excluding energy tax and VAT: natural gas 5.9 euro/GJ; electricity 0.08 euro/kWh. b) 25% of the recovered CO2 is used in greenhouses; 75% is stored underground in empty natural gas fields. c) Climate neutrality compared to the reference in the former column.

Our analysis shows that the emissions from the total production chain of climate neutral hydrogen range from 17 and 33 kg of carbon dioxide equivalents per gigajoule. For comparison the emissions of natural gas for the whole production chain amount to 60 kg CO2-eq/GJ. The climate neutrality of the hydrogen amounts to about 71% when natural gas is used as feedstock, and to about 46% when coal is used. The emissions from the total production chain of climate neutral electricity amount to between 0.2 and 0.5 kg of carbon dioxide equivalents per kWh. For comparison, the emissions of electricity production facilities currently in operation range from about 0.4 to 1.1 kgCO2-eq/kWh. The climate neutrality ranges from 21% to 75%, depending on the application/storage of the recovered CO2 and the electricity production reference used. The calculated production costs for hydrogen ranges from 13 to 16 euro/GJ of hydrogen, whereas the current price for natural gas for end-users (excluding energy tax and VAT) is approximately 6 euro/GJ. The calculated production costs for electricity ranges from 8 to 11 euroct/kWh in the situation where the producer of the electricity delivers the CO2 for free to the customer (either a methanol producer or a greenhouse grower). The eight cents per k W h reflects the production costs of a new concepts for a zero

1168 emission plant in the USA, which is still in an early stage of development. However, in case the customer of the CO2 is willing to pay a price for the CO2, equalling the marginal costs of the energy saved by the customer, the electricity price could drop to 5 to 9 euroct/kWh. For comparison the current price for electricity for end-consumers (excluding energy tax and VAT) is approximately 8 euroct/kWh. The specific reduction costs for climate neutral hydrogen (using a discount rate of 5%) ranges from 150-250 euro/Mg of CO2. In the examined production chains the specific reduction costs for climate neutral electricity is very sensitive to the assumptions with regard to the energy price. The costs range from less than zero to 30 euro/Mg of CO2 avoided. SENSITIVITY OF RESULTS In the case of hydrogen production, generally only emission changes in chain element 3 (production of the climate neutral energy carrier and compression of the CO2) are substantial, and contribute up to 80% of the total emissions of the whole chain. In the case of electricity, generally only changes in emission in chain element 7 (end use of energy carrier) are substantial. Emission changes in element 1 (extraction and production of the fossil energy carrier) are only relevant when the (methane) emission factor of the fossil fuel used for the production of the climate neutral energy carrier differs substantially from the (methane) emission factor of the fossil fuel used in the reference system. Emission changes due to storage are negligible. However, in cases where the CO2 is applied in other production processes, e.g. in greenhouses, it has to be carefully analysed which part of the CO2 is stored in the product and which part of the CO2 is emitted to the atmosphere. The costs for climate neutral energy carriers are sensitive to the scale of production. In our analysis we assumed an annual production of 5 million gigajoule of hydrogen or electricity. A production unit twice as large as assumed in this study, might lead to a cost reduction of 10 to 15%. CONCLUSIONS Climate neutral electricity can be produced in the Netherlands at about 11 euroct/kWh, which is about 3 euroct/kWh higher than current electricity prices. To be competitive, financial support of about 3 euroct/kWh will be required. The climate neutrality of electricity in the examined cases varied between about 20 and 75% depending on the technology and reference used. When the financial support is applied to 100% climate neutral energy carriers only, the financial support should be about 4 and 12 euroct per 100%-climate neutral electricity in order to be competitive. This financial support can be lower, when enduser of carbon dioxide (e.g. greenhouse growers) are willing to pay a price for the recovered carbon dioxide. The production of hydrogen to replace natural gas in the grid is currently expensive. Climate neutral hydrogen production costs ranges from 13 to 16 euro/GJ, while climate neutrality ranges from 50% (coal gas as feedstock) to 70% (natural gas as feedstock). Current natural gas price is 6 euro/GJ. To cover the additional production costs (of the examined production chains), financial support between about 20 and 30 euro per 100% -climate neutral hydrogen will be required.

ACKNOWLEDGEMENT The authors want to thank the National Institute of Public Health and Environment and the members of the Interdepartmental working group 'Regulation Climate Neutral Energy Carriers' with representatives from the Ministries of Environment, Finance and Economic Affairs for their suggestions with respect to the content of the study and for their financial support.

REFERENCES I. Hendriks, C.A., Harmelink, M., Hofmans, Y., and De Jager, D. (2002) Climate neutral energy carriers in the regulatory energy tax (REB), Ecofys Energy and Environment, Utrecht, the Netherlands.

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1171

POSSIBLE I M P E R F E C T I O N OF I N T E R N A T I O N A L EMISSIONS T R A D I N G U N D E R THE EXISTENCE OF HOT AIR Akira Maeda Faculty of Policy Management, Keio University, 5322, Endo, Fujisawa, 252-8520, Japan

ABSTRACT This paper develops analytical models of emissions markets in which a large number of homogeneous regulated emitters participate, and analyzes sufficient conditions of initial permit distribution for the emergence of emitters with the market power. The conditions obtained give interesting policy implications for the hot air issue: the possibility of hot air is not just a political debate but also a more fundamental economic issue that is relevant to market efficiency.

INTRODUCTION

Market trading of emissions permits is widely considered to offer the least expensive means of meeting emission targets of greenhouse gases (GHGs), in particular carbon dioxide (CO2). ~ Moreover, it is considered that problems caused by environmental externalities can be resolved in an efficient manner by negotiations between parties involved when property rights are properly defined. Assuming that there is no transaction cost required and that no income effect is incurred, the equilibrium is independent from the initial allocation of property rights, which is the well-known Coase theorem, due to Coase [2]. One of the important premises behind these theories is that markets are perfectly competitive in a sense that all market participants are price-takers and no one can have the ability of controlling the market. Without the premise, emissions markets would not necessarily work in an efficient manner. Several studies have been conducted on the issue of market power in emissions markets, including Hahn [4] and van Egteren and Weber [7]. Their studies focus upon the behavior of market participants with market power in an emissions market and discuss the economic consequences. They commonly imply that the concentration of initial permit allocation to a specific regulated emitter would strengthen its market power and the degree of inefficiency of the market. The implication itself quite makes sense in that a market participant who initially holds a large proportion of permits available in the market would behave as a monopolist. The role of regulatory authorities, on the other hand, is to prevent the market from becoming the one in which regulated emitters with market power exist. From the regulator's point of view, it might be less For an extensive survey of the literature of market-based environmental policy instruments, including tradable permits, see Cropper and Oates [3]. For detailed discussion of the standard theory of emissions trading and the economic benefits it offers, see, for example, Montgomery [5], Baumol and Oates [1 ], and Tietenberg [6].

1172 important to analyze the consequence of the existence of market power. Rather, it is important to understand how many permits, initially allocated to each regulated emitter by an authority, would bring an emitter market power. In short, regulatory authorities designing and implementing permit markets need to understand what condition regarding initial permit allocation would sufficiently allow the emergence of emitters who hold strong market power. The answer key for sufficient conditions of initial permit allocation is not found at all in any previous studies including Hahn, and van Egteren and Weber. The Kyoto protocol, which has already been ratified or is in the process of ratification in many countries in these days, addresses emission targets for countries involved. Unconstrained emissions, which are emissions if no abatement efforts would be made, in the first compliance period of years from 2008 to 2012 will shortly be estimated. Subsequently, the actually necessary or redundant volume of emission right will be revealed for each country. Some countries in economic transition including Russia and Ukraine are predicted to hold a large volume of redundant emission right, which is known as "hot air." Some critics point out that due to the hot air, these countries in economic transition will not just be reluctant to make an effort in reducing greenhouse gas emissions, but also be able to benefit from the sale of hot air under the Kyoto mechanism, in particular the international emissions trading (IET) regime. Although the criticism itself does not make sense from the perspective of economic theory, 2 the possibility that hot air may cause market inefficiency cannot be excluded. However, it is regrettable that there is no theory or study that indicates how much hot air held by Russia and Ukraine specifically would give them the ability to control the international emissions market in future. This paper develops analytical models of emissions markets in which a large number of homogeneous regulated emitters participate, and analyzes sufficient conditions for the emergence of emitters with market power. Emitters considered are homogeneous in the sense that they have similar unconstrained emissions and similar emission abatement cost structure. Due to the homogeneity, the emissions market considered seems competitive at a first glance. The present paper shows whether it is the case or not depends upon initial emissions permit distribution. It yields conditions of initial distribution that are sufficient for the emergence of market power. The results obtained have interesting policy implications for the hot air issue: the possibility of hot air is not just a political debate but also a more fundamental economic issue that is relevant to market efficiency.

ANALYTICAL FRAME Consider an emissions market in which there are N regulated emitters engaging in permit trading. The notations in this model are defined as follows. i = 1... N: Regulated emitters. x, : Emissions abatement by emitter i. ( >_0 ) C , ( X , ) - c , X 2/2: Abatement cost function for emitter i. (Marginal abatement cost functions are assumed to be linear in X.) G,. : Unconstrained emissions by emitter i. (Emissions if abatement actions would not be taken at all.) Y,' Initial endowment of permits to emitter i. (They are assumed to be given to emitters gratis.) Oi =-Gi- Yi: The difference between unconstrained emission and initial permit holding. (When D i >__0, it indicates that the emitter will run out of permits. On the other hand, when Di < 0, it indicates that the emitter has redundant permits.) S: Emission permit market prices.

2 As long as the idea of the introduction of market mechanism to cope with the greenhouse issue is accepted, benefiting from market trades without any emission abatement effort should be considered as a rational economic behavior and being necessary for the development of efficient market. Therefore, the prevailing debate on hot air seems misleading, and is not properly addressed as an economic issue while the issue itself might be politically important.

1173 r,: The number of permits bought by emitter i. (T, _0 "selling.")

indicates "buying," while T, _0 indicates

For the simplicity of description, the following notations are also introduced. Ak -

c[ ~

, Bk

=

D i i=k

Notice that B, represents net shortage of initial permits necessary for compliance for emitters k to N. When an emitter behaves as price-taker in the market, the emitter faces a problem of deciding both permit trade and the level of emission abatement. The decision problem is described as follows. Min S. T,. + ciX 2/2 x,_>o,~, s.t. D~-X~-T,. -O, Tt

s.t. D , - X , - T ~

0 and - B3 - D~ < T2 _< - B

7'1° = [D,, - B 3 - T2]

if

D, __ 0

and

3-

cl Di, C, + A 3

and

T2 < - B 3 - D , .

Emitter 2 also solves a similar problem. Then, the equilibrium price is calculated as s~o,, =-S(T,*',T~*). Let me add an assumption on abatement cost structure and initial emissions distribution as follows.

Assumption 6 (Simplification) 1) Given Assumption 4, the initial permit holding of Emitter 1 exceeds its unconstrained emission. On the D 2 > O. other hand, that o f Emitter 2 is less than its unconstrained emission. That is" D, < 0, 2) Emitters 1 and 2 have the same abatement cost function. That is: c, = c: - c . 3) The aggregate unconstrained emission out of other emitters, excluding Emitters 1 and 2, is equal to the aggregate emission target for them. In other words, net shortage or redundancy o f permits is zero. That is:

B,- '~-'~ (G, - Y,.): 0. i=3

The following proposition is obtained. (The proof is omitted due to the limited space.)

Proposition 2 (Nash equilibrium price and competitive price) Given Assumptions 4, 5, and 6, I) Scorn,>- SNo,h > 0 if D 2 > II) SN~sh>-Scomp> 0 if

2c + 3A 3

c+A 3

D I > 0,

- 2c + 3A 3 DI > D2 > - D ~ > 0 , C'k'A 3

and

III) Su~,h > Stomp = 0 if -D, >_D2 > 0. When N is large enough to take a limit to the infinity, we have `43 ~ o, which yields (2c + 3,43)/(c + `43)-~ 2. Then the following approximation holds. I) Sco~, -> SN~ > 0 if D 2 > -2D 1 > 0, II) SN~h >-Sco,, > 0 if -2D I > D 2 > -D l >_0, and III) SNa,h > Scoop = 0 if -D, _ D 2 > 0.

1176 The above proposition is interpreted as follows. Due to the initial permit allocation, Emitter 1 is basically a permit seller while Emitter 2 is a permit buyer. If excess amount of permits of Emitter 1 roughly exceeds the half of necessary amount for Emitter 2 (in an exact account, (c +A3)/(2c+3,43)), then Emitter 1 can exert its negotiation power on Emitter 2 and can set a selling price higher than the competitive market price. (Case II.) Moreover, if excess amount of Emitter l's permits exceeds the necessary amount for Emitter 2, the market price is supposed to be zero in a competitive market because the rest of trade requirement is assumed to be zero. However, the equilibrium price results in being strictly positive. (Case III.) To the contrary, if excess permits of Emitter 1 do not reach to the half of necessary volume of Emitter 2 (again, in an exact account, (c + A3)/(2c + 3A3)), then Emitter 2 in turn has a negotiation power to set a buying price lower than the competitive market price. (Case I.). Let me apply the above result to the interpretation of the Kyoto protocol. While the economies in transition such as Russia and Ukraine are estimated to hold the large amount of the hot air, Japan, Canada, Australia and other "umbrella countries" are estimated to have to make a strong effort to reduce emissions. In fact, Japanese GHG emission has been growing since 1990. Some estimates say that EU countries are not actually required to reduce emissions because the concept of the EU bubble allows them to trade emissions within the EU region. It is realized that the setting addressed in Assumptions 4, 5, and 6 reflects the current situation: Russia and Ukraine as Emitter 1, and Japan and other umbrella countries as Emitter 2. Proposition 2 tells that how large the volume of the hot air is, compared to the abatement requirements for Japan and other countries, is critical to whether or not Japan will be able to have negotiation power against Russia and Ukraine. If the hot air roughly exceeds the half of abatement requirement for Japan and others, Japan will be obliged to pay higher prices. Otherwise, Japan will be able to pull down prices by negotiation. CONCLUSIONS The findings of this study are addressed as Propositions 1 and 2. These propositions challenge a prevailing idea originating from Coase [2], the idea that the achievement of economic efficiency of markets is independent from the initial distribution of property rights, given that no transaction cost nor income effects exist. I am sure that the results here have never pointed out in the standard theory of tradable permits, too. In the context of the Kyoto protocol, the results indicate that the hot air issue is related, in a subtle way, to the economic efficiency (or inefficiency) that the Kyoto mechanism is supposed to offer. Policy makers are advised to give a deep thought to the results in order to actually implement the Kyoto mechanism in an efficient manner.

REFERENCES

1. 2. 3. 4. 5. 6. 7.

Baumol, William J. and Wallace E. Oates (1988), The Theory of Environmental Policy, Second Edition, Cambridge University Press. Coase, Ronald H. (1960) The Problem of Social Cost, Journal of Law and Economics, III, 1-44. Cropper, Maureen L. and Wallace E. Oates (1992), Environmental Economics: A Survey, Journal of Economic Literature, 30, 675-740. Hahn, Robert W. (1984), Market Power and Transferable Property Rights, Quarterly Journal of Economics, November, 753-765. Montgomery, David W. (1972), Markets in Licenses and Efficient Pollution Control Programs, Journal of Economic Theory, 5,395-418. Tietenberg, Thomas H. (1985), Emissions Trading: An Exercise in Reforming Pollution Policy, Resources for the Future, Washington, D.C. van Egteren, Henry and Marian Weber (1996), Marketable Permits, Market Power, and Cheating, Journal of Environmental Economics and Management, 30, 2, March, 161-73.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1177

THE EFFECT OF EMISSIONS TRADING AND CARBON SEQUESTRATION ON THE COST OF CO2 EMISSIONS MITIGATION Natesan Mahasenanl, Michael J. Scott l, and Steven J. Smith 2 1Pacific Northwest National Laboratory/Battelle, Richland, WA 99352, USA. 2joint Global Change Research Institute, Pacific Northwest National Laboratory/University of Maryland, College Park, MD 20740, USA.

ABSTRACT

The deployment of carbon capture and sequestration (CC&S) technologies is greatly affected by the marginal cost of controlling carbon emissions. Emissions limits that are more stringent in the near term imply higher near-term marginal costs and therefore encourage the deployment of CC&S technologies. In addition, allowing the trading of emissions obligations lowers the cost of meeting any regional or global emissions limit and so affects the rate of penetration of CC&S technologies. In this paper, we examine the effects of the availability of sequestration opportunities and emissions trading (either within select regions or globally) on the cost of emissions mitigation and compliance with different emissions reduction targets for the IPCC SRES scenarios. For each base scenario and emissions target, we examine the issues outlined above and present quantitative estimates for the impacts of trade and the availability of CC&S technologies in meeting emissions limitation obligations.

INTRODUCTION

Carbon capture and sequestration (CC&S) technologies remove carbon from emissions streams or the atmosphere and seek to sequester it in one way or another for a very long time. As such, deployment of CC&S technologies can be an important component of efforts to meet future emissions limits, either regionally or globally, and in the reduction of compliance costs. The magnitude and timing of sequestration opportunities and the opportunity to trade emissions permits affect the value of carbon, and therefore the cost of compliance. Trade lowers the marginal value of carbon in high-cost regions and raises it in low-cost regions [1]. In this paper we examine the issues outlined above and present quantitative estimates for the impacts on the marginal cost of carbon as well as the cost of compliance with a climate policy of stabilizing atmospheric CO2 concentrations at twice pre-industrial levels. We use PNNL's MiniCAM model version 2001 [2,3] as the analytical foundation for the analysis. MiniCAM is an integrated assessment model of global change. It includes representations of both the world's energy and agriculture systems for 14 world regions. Engineered capture and sequestration technologies are modeled generically in terms of their cost and performance characteristics. Carbon capture is explicitly represented in the model at key fuel transformation nodes. CC&S technologies are adopted if the economics are favorable. Terrestrial sequestration (in forests, agricultural soils, etc.) and sequestration in the ocean is not included in this analysis. We also model three cases in which varying degrees of trading are utilized to achieve a carbon mitigation path that results in a long-term atmospheric CO2 concentration of 550 ppm by the end of the century. The 550 ppm target or WRE550 is discussed extensively elsewhere [4]. In looking at long-term stabilization of atmospheric CO2 concentrations (as opposed to relatively short term efforts like the current Kyoto

1178 Protocol), it must be noted that the developing regions of the world markedly increase their emissions over the next century. Attaining a stable atmospheric concentration of 550 ppm by the end of the 21 st century cannot be achieved by the developed regions of the world (modeled here as the Annex I counties in the United Nations Framework on Climate Change (UNFCC)) alone--the non-Annex I countries have to undertake significant emissions controls. For our trading cases, therefore, we consider the following:

•

•

•

No T r a d e - - E a c h nation (region) undertakes its own emissions reduction and sequestration independently. There are many possible ways in which the WRE550 responsibilities could be specified. For this paper, we assume that individual Annex I country responsibilities are equal to those in the WRE550 case until 2020. Non-Annex I countries undertake no emission reductions until their combined emissions reach the same total as those of the Annex I countries (half the world total). This happens about 2020. Individual regions are then assigned emissions budgets under one of two allocation schemes described below. A n n e x I T r a d e - - R e s p o n s i b i l i t i e s are the same as in the no-trade case. The United States, Japan, Western Europe, Canada, Australia-New Zealand, Eastern Europe, and the Former Soviet Union create a trading block to trade carbon emissions permits (and in some cases, carbon sequestration credits). Non-Annex I countries retain individual country responsibilities. W o r m T r a d e - - A l l countries in the world trade emissions permits and sequestration credits. The same responsibility issues apply as in the previous two cases.

We also consider two different schemes for allocating the WRE550 emissions budget amongst the individual regions. These are: •

•

S c h e m e 1: Each country is allocated an amount of from the WRE550 emissions budget equivalent to its share of worldwide emissions for the unconstrained (base) case for each year in the remainder of the forecast period. For example, if China has 20% and 18% of the world's emissions in 2035 and 2050 under the base case, it is assigned the same % of the WRE550 budget in 2035 and 2050. S c h e m e 2: Emissions responsibilities after 2020 are assigned to each region in the 550ppm case according to the share of worldwide emissions in 2020. For example, if China has 19% of the world's emissions in 2020, it is assigned 19% of the world's emission budget under WRE550 for the remainder of the forecast period.

It must be stressed that these are two relatively simple allocations schemes, out of an infinite number of possibilities. Initial allocation of emissions budgets is a critical issue under climate policy, with literally trillions of dollars at stake over the next century. These two schemes were chosen purely for illustrative purposes. Scheme 1 seeks to proportionally reduce the emissions in each region, while Scheme 2 will require disproportionate percentage reductions in emissions over time, since regions with significant growth in emissions in the base case will need to reduce a larger fraction of their emissions. In looking at the future over long time horizons it is necessary to examine a number of plausible future pathways. We use a suite of scenarios documented in the Special Report on Emissions Scenarios (SRES) developed under the auspices of the Intergovernmental Panel on Climate Change (IPCC) and described in detail elsewhere [5]. The SRES scenarios are grouped in four families, each with a specific qualitative storyline that guides the numerical quantification of the scenarios. The scenarios are split along two primary dimensions (1 or 2, and A or B). The four scenarios families are, therefore, denoted as: A1, A2, B l, and B2. The A1 scenario has Sub-scenarios based on energy choices (balanced, fossil-intensive, emphasis on renewables, etc.). We show results from the B2 scenario in this analysis. Results for the other scenarios are similar.

Modeling Engineered Carbon Capture and Sequestration Technologies We base our energy penalty for carbon capture on Herzog et al [6] and assume that the phasing in of these more efficient capture technologies will occur gradually and will be completed 50 years after the initiation of carbon capture. Our assumptions on the additional capital investment for the CO2 capture system are based on the work of Gottlicher and Pruschek [7] and their comprehensive survey of over 300 studies of

1179 COz removal systems from fossil-fueled power plants, with the same assumption about costs decreasing over time. Freund and Ormerod [8] cite estimates for transport and disposal costs that range from $4.7/metric ton of CO2 to $21/metric ton of CO2 ($17/tC to $77/tC), depending upon the type and location of the sink. A similar range is estimated in more recent work [9]. We assume an intermediate value of $10/metric ton CO2, which works out to $37/metric ton C for all transport and disposal costs and hold this cost constant throughout the time period under study. Other estimates for specific transport and disposal opportunities vary from net savings in the case of using unminable coal and depleted oil fields to greater than $1000/tC for hydrates [10] to values in between [11]. We acknowledge the wide range of costs possible for specific transport and disposal but use the Freund and Ormerod [8] range as indicative of the distribution of the average cost of all opportunities. The results presented here are robust across this range of costs.

RESULTS No Trade Case The no-trade case begins with business as usual emissions through the early part of the 21 st century. By 2020, however, countries have to begin to reduce their carbon emissions from the path they otherwise would have followed per the shares described earlier. With sequestration options available, the amount of emissions can be higher by the net amount sequestered. In addition, the marginal and total costs of emissions control can be lower with CC&S. The cost of compliance under the B2 scenario with a 550 ppm climate policy under the two allocation schemes is shown in Figure 1. It is seen that CC&S can significantly lower the cost of compliance with the policy under either allocation scheme. It is also seen from Figure 1 that compliance costs under Scheme 1 are lower than the costs under Scheme 2. This is because the disproportionate reductions required in the developing regions under Scheme 2 leads to higher marginal values of carbon and therefore higher compliance costs. Under Scheme 1 (proportional reductions), the marginal values of carbon are lower in the developing regions (which account for a majority of the emissions worldwide by the end of the century), leading to lower compliance costs. It is also seen that in the middle of the next century, before the marginal values of carbon get high enough for widespread deployment of engineered CC&S, that compliance costs under Scheme 1 without CC&S can be cheaper than under Scheme 2 with CC&S.

2.5 - 0 - Scheme ! -A--Scheme 1 with CC&S

.~_ 1.5 ~

- 0 - Scheme 2 ---)(-- Scheme 2 with CC&S

1

~ 0.5 r~ 0 o

•--,

f'4

¢',1

o

~

¢',1

o

¢',1

~-1

t',l

Figure 1. Cost of compliance with 550 ppm policy under SRES B2 scenario with no trade Annex I Trading Case If trading in emission permits is allowed, it opens up the possibility of reducing the marginal costs of emissions abatement, as countries with higher marginal costs of emissions abatement purchase emissions permits from countries with lower marginal costs of abatement. Significant savings in total abatement costs can be realized from reallocating the actual carbon abatement. Figure 2 compares the cost of compliance with the 550 ppm climate policy under the SRES B2 scenario for the two allocation schemes, without CC&S. It is seen that while Scheme I realizes essentially no savings from limited trade, but has lower compliance costs than Scheme 2, even with trade. The lack of savings from trade in Scheme 1 is

1180

due to very similar marginal values for carbon in the Annex-I regions, reducing the potential for savings from trade. The savings from Annex-I trade are small even for Scheme 2, due to the similar marginal carbon values within the Annex-I regions. Note that the marginal value of carbon in a region depends on both the magnitude of emissions reductions and the proportion of fossil fuels in the energy mix, while the potential for savings from trade are dependent are differences in the marginal values of carbon.

3 ~" 2.5

-D-

S c h e m e 1- N o T r a d e

---A-- S c h e m e 1- A n n e x I Trade

1.5

---- S c h e m e 2- N o T r a d e

iI I ---)6- S c h e m e 2- A n n e x I k_ Trade

0.5 0 .--

¢,,i

¢,q

t--,l

¢,,I

t-,,i

t-,,i

Figure 2. Effect of Annex-I trade on cost of compliance under SRES B2 scenario The effects of trade and CC&S under Scheme 2 are shown in Figure 3. It is seen that the reduction in compliance costs with CC&S is much greater than the reductions realized through Annex I trade. I

I i

2.5

No Trade or CC&S

i

---A-- A n n e x I T r a d e Only t .~

1.5

-~- ccs~s o ~ A m e x I T r a d e with

cc~

9 0.5 0

.......jjI I i

I •--

¢q

cq

¢,q

t-,i

¢,,I

¢,,I

¢q

Figure 3. Savings from Annex I trade and CC&S for Scheme 2 under SRES B2 scenario

World Trading Case The gains from emissions trading are potentially much greater if the group of nations undertaking reductions could be expanded to include the non-Annex I countries as well as the Annex I countries. However, for Scheme 1, there is very little savings realized with worldwide trade, due to similar marginal carbon values worldwide. The savings from worldwide trade as compared to no trade and Annex I trade under Scheme 2 is shown in Figure 4. Note that the cost of compliance with the 550 ppm policy with worldwide trade is the same for the two allocation schemes, since the cost is determined by the overall emissions budget rather than regional allocations.

1181

~" 2.5

i - O - - N o Trade

._

1.5

~ O

'

I -~-

A n n e x I Trade 1

,~

World_Tra.de_. J

0.5

--

e~l

¢'q

t~l

t~l

~

eq

¢'4

Figure 4. Cost of compliance with 550 ppm policy for Scheme 2 under different trade cases It is clear that in the absence of CC&S technologies, worldwide trading leads to the lowest cost of compliance. This cost is compared with the cost of compliance with CC&S under different trade cases in Figure 5. It is seen that cost of compliance is lowest with the availability of worldwide trading opportunities as well as CC&S technologies. By the end of the century, the cost of compliance with the 550 ppm policy is significantly lower with no trade (or Annex I trade) but with engineered CC&S than with worldwide trading without engineered CC&S. However, in the middle of the next century, worldwide trade without CC&S is cheaper than no trade or Annex I trade scenarios with CC&S. This is because the marginal values of carbon are not yet high enough to encourage widespread deployment of CC&S technologies. Alternatively, until the cost of CC&S is lower than the marginal value of carbon at a given point in time, worldwide trading may lead to lower cost of compliance with climate policy. Therefore, a limited period of worldwide trade without CC&S can lead to a lower cost trajectory for compliance with climate policy than for cases with CC&S and no trade or Annex I trade.

2.5

[

- n - : Woria Tr~a-e-~-o---I CC&S World Trade with CC&S

1.5

t

- - 0 - N o Trade with CC&S

1

!

---N-- Annex I Trade CC&S

0.5

I i

.....

_ ~ ~ ~ ~ Figure 5. Cost of compliance with 550 ppm policy under different trade cases with and without CC&S

CONCLUSIONS The paper has demonstrated that engineered CC&S technologies can significantly reduce the marginal cost, and thereby total cost, of stabilizing the carbon concentration of the earth's atmosphere. This effect is independent of the trading regime that is in place. We have also demonstrated that savings due to trading in emissions limitations obligations are dependent on the allocation of emissions reduction obligations worldwide.

1182 There is some uncertainty over the permanence of engineered sequestration technologies, and the impacts of impermanent sequestration on carbon abatement or its cost will not be significant in the 21 st century, although they could add considerably more to the cost of abatement in the 22 nd century [ 12]. This is an important consideration that was not studied in the current work. While the results shown here are robust across a modest range of global average costs for transport and disposal of CO2, additional work in ascertaining the spatial and time distribution of average and marginal costs is necessary. Further study in these areas is essential to better understand the role of CC&S in climate policy.

REFERENCES

1. Edmonds, J., Scott, M.J., Roop, J.M. and McCracken, C.N. (1999). International Emissions Trading and Global Climate Change. Pew Center on Global Climate Change, Arlington, Virginia. 2. Dooley, J.J., Edmonds, J.A. and Wise, M.A. (1999). The Role Of Carbon Capture & Sequestration in a Long-Term Technology Strategy of Atmospheric Stabilization. PNNL-SA-30206. Pacific Northwest National Laboratory, Washington, DC. 3. Edmonds, J.A., Wise, M.A., Sands, R., Brown, R. and Kheshgi, H. (1996). Agriculture, Land-Use, and Commercial Biomass Energy." A Preliminary Integrated Analysis of the Potential Role of Biomass Energy for Reducing Future Greenhouse Related Emissions. PNNL-11155. Pacific Northwest National Laboratory, Washington, DC. 4. Wigley, T.M.L., Richels, R. & Edmonds, J.A. (1996). Nature. 379(6562):240. 5. Nakicenovic, N. and Swart, R., eds. (2000). Special Report on Emissions Scenarios. Cambridge University Press, Cambridge, U.K. 6. Herzog, H., Drake, E., and Adams, E. (1997). C02 Capture, Reuse, and Storage Technologies for Mitigation Global Climate Change. Energy Laboratory, Massachusetts Institute of Technology, Cambridge, MA. 7. Gottlicher, G and Pruschek, R. (1997). Energy Conversion and Management. 38 (Supplement): S173. 8. Freund, P" and Ormerod, W.G. (1997). Energy Conversion and Management. 38 (Supplement): S199. 9. International Energy Agency (IEA). (2001). Putting Carbon Back in the Ground. IEA Greenhouse Gas R&D Programme, Stoke Orchard, Cheltenham, Gloucestershire, U. K. 10. Freund, P. (2000). Progress in Understanding the Potential Role of C02 Storage. Fifth International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, August 1316, 2000. 11. Stevens, S.H., Kuuskraa, V.A. and Gale, J. (2000). Sequestration of C02 in Depleted Oil and Gas Fields: Global Capacity, Costs, and Barriers. Fifth International Conference on Greenhouse Gas Control Technologies, Cairns, Australia, August 13-16, 2000. 12. Scott, M.J., Edmonds, J.A., Mahasenan, N., Roop, J.M, Brunello, A.L., Haites, E.F. (2001). International Emission Trading and the Cost of Greenhouse Gas Emissions Mitigation and Sequestration, First National Conference on Carbon Sequestration, Washington, D.C., May 14-17, 2001.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1183

CO2 EMISSIONS TRADING MARKET SYSTEMS AS AN ENVIRONMENTAL POLICY OPTION AND ASSESSMENT OF ITS EFFECT - EVALUATING INTERTEMPORAL TRADING IN PARTICULAR

Kazuya Fujime Managing Director & Chief Executive Economist, IEEJ, Inui Bldg., Kachidoki, 13-1, Kachidoki 1-chome, Chuo-ku, Tokyo 104-0054 JAPAN

ABSTRACT

In the theory of economics, to get the whole of GHG reduction targets satisfied efficiently, it is imperative to set a target amount of GHG reductions achievable by each country at a marginal cost equal to all countries. But, there is actually a gap between theory and a given target. In efficiency terms, it is desirable if each country could freely trade on the market "gap," or any difference between an optimal reduction amount for a country and a target specified by the politically compromised Kyoto Protocol. Emissions trading provides a mechanism of adjustment by selling or buying emissions (emissions permits). To explain clearly why emissions trading can have a cost reduction effect with a theoretical model in use, this paper first verifies an inherent function of emissions trading, which helps minimize a total reduction in cost by adjusting any "gap" between optimal and political targets, in both spatial and temporal terms. A Lagrangian function of a bilateral two-period trading model is used in the verification. Also, in order to demonstrate an effect of intertemporal trading, the "World Energy Industry Model," originally provided with an inter-area emissions trading function, was modified and given an additional intertemporal trading function to inter-area one before nan for simulation.

INTRODUCTION

This paper intends to offer an in-depth examination from the standpoint of economics of the "Kyoto Protocol" generally perceived as a product of intemational coherence in global warming abatement. A collective target set under the Kyoto Protocol requires industrialized countries to cut their combined greenhouse gas (GHG) emissions as of 2010 to a level "their annual average emissions in 2008--2012 should stay 5.2% below 1990 records." The Protocol also specifies reduction targets to be met by individual countries (areas). On top of the commitment period up to 2010 proposed under the Kyoto Protocol, during which specified targets should be met, subsequent five-year commitment periods to 2015, 2020, 2025 and 2030, each, were set and two scenarios were prepared. One is a "business-as-usual (BAU)" scenario in which the Kyoto

1184

target would remain unchanged even in the post-2010 periods. The other is a "tightening environmental constraint (TEC)" scenario, which assumes the Kyoto target would be the tighter in the later commitment periods. By varying banking and borrowing conditions, each scenario was simulated in a total of 36 cases. Simulation results showed that intertemporal trading was effective in cutting the emissions reduction cost by 3~26% in the BUA case, and by 4--7% in the TEC case, thus proving a cost reduction effect of intertemporal trading thanks to its temporal flexibility. Based on consideration described in this paper, the Kyoto Protocol can be counted as the first step toward warming abatement. In the capacity of environmental policy, the protocol can be evaluated as a step forward.

TOTAL COST MINMIZATION AND OPTIMAL SOLUTION BY BILATERAL TWO-PERIOD TRADING MODEL Emissions trading in a broad sense will be in practice multilaterally and over multiple periods. But, for simplification purposes, a theoretical model of bilateral two-period trading is used here in clarifying the essential nature of emissions trading, in which trading is in goods called emissions permits. In stricter terms, this model deals in synchronous bilateral trading, but does not cover intertemporal trading within a single country. On the contrary, intertemporal trading includes not the former but the latter. Anyhow, it remains unchanged that this theoretical model can explain theoretical grounds for the inherent function to emissions trading to help adjust any "gap" between an optimal solution and a political target. With bilateral two-period trading expressed in equations, the question of how to minimize the emissions reduction cost can be solved as described below. Xl=First country's CO2 reductions X2= Second country's CO2 reductions Yl=ax~ First country's marginal reduction cost curve Ya=bx2 Second country's marginal reduction cost curve Yli=First country's marginal reduction cost in i period, i=l, 2 yli=First country's total reduction cost in i period, i=l, 2 Y i=Second country's total reduction cost in i period, i=l, 2 2

i

yl=Eyl =: First country's total reduction cost throughout a given period, i=l, 2 y2=Ey2i=: Second country's total reduction cost throughout a given period, i= 1,2 y=yl+y2=: World's total reduction cost throughout a given period Y=l/2(a(x1')2+a(x,Z)2CDR+b(x2')2+b(x22)2CDR) (To be explained at the end of this section.) CDR=Composite discount rate=(1 +p)x(l +s)/(1 +r) x (1+t) xll=First country's optimal reductions throughout a given period Xl2=First country's optimal reductions in the second period x21=Second country's optimal reductions throughout a given period x22=Second country's optimal reductions in the second period Min Y, constraints are put as follows: (s, t)

~ ~-~x/= xll+x12+x21+x22=~ i=1 j = l

1185 Here, Rangange's equations are put as follows.

L(Xl 1...... X22,K)=Y+K (O,--X11--X12--X21--X22) Z,represents a marginal reduction cost. Xll x12 XEl'X22~"are differentiated.

~L/~x11=LI l--ax i 1-~,1==0

(1)

8L/Sx12=L12=aXl2CDR-~.=0

(2)

8L/Sx21=n2 l--bx21-~L=0

(3)

8I_JSx22=L22=bx22CDR-K=:0

(4)

8n/8~L=L~.=fx-x11-Xl2-x21-x22=:0

(5)

xll=K/a

Xl2=L/aCDR

X21=~]9

x22=~oCDR

With these put in the equations (5): ot-L/a-L/aCDR-L/b-L/bCDR =~-K (l/a+ 1/aCDR+ l/b+ 1/bCDR)=0 Hence, ;~=w'(1/a+I/aCDR+I/b+I/bCDR) = w'(1/a+l/b)+(1/a+l/b)/CDR=ot/(1/a+l/b)(l+l/CDR) Accordingly, Xl1=L/a=-~a(1/a+ I/b)( 1+ 1/CDR)= ~(1 +a/b)(1 + 1/CDR) x~2=L/aCDR=~(1 +a/b)(1 +I/CDR)CDR=w'(1 +a/b)(1+CDR)

X21=~/b:(L/b( I/a+ l/b)(1 + 1/CDR)=ot/(1+b/a)(1 + 1/CDR) x22=~j]gCDR=oJ(1 +b/a)(1+ 1/CDR)CDR=w'(1 +b/a)(1 + 1/CDR) Y(the world's minimum total reduction cost)can be described as follows. Y=Yl l+yl2+y21+Y22

yll=axllxll/2=a(xll)2/2

Yl2=aCDRxl 2xl2/2=aCDR(xl2)2/2

y21--Bx2Ix21/2__b(X21)2/2 y22=bCDRx22x22/2=bCDR(x22)2/2y=(1/2)(a (x11)2+a(x12)2CDR+b(x21)2+b(x22)2CDR

THEORETICAL GROUNDS FOR EMISSIONS REDUCTION COST CU'ITING EFFECT

INHERENT TO INTERTEMPORAL TRADING First, the tools provided by intertemporal trading are banking and borrowing of emissions permits. Literally banking means to bank emissions permits, consumable in a coming period, otherwise sold or leased.

1186 Borrowing means to borrow emissions permits to be consumed during a current period, with equivalent ones to be paid back in a coming period. Theoretically not only trading partners include others (other areas) but also owned permits in current or coming periods are tradable. Moreover, a coming period is not limited to the next period to come but includes any period ahead. Effects of intertemporal trading have analogy with those of spatial trading, which means this trading can be considered as if temporal dimensions were identical to spatial dimensions. However, affected by interest rate, technological advance, aggravating capacity of COz sinks, emissions-permits price rises, etc., intertemporal trading itself does not allow application of a simple analogy by extrapolating the emissions cutting effect of spatial trading. It is because intertemporal trading requires changing conditions with time to be taken into consideration, a crucial difference from spatial trading. Listed below are major variables that are assunaed to affect intertemporal trading: Emissions-permits price increase (%/year): p Interest rate (%year): r Rate of technological advance (%year): t Rate of aggravating capacity of COz sinks (rate of gradually diminishing capacity with time of such sinks as oceans)(%year): s Of these variables, it is p and s that can facilitate banking of emissions, or emissions pemaits, by cutting more emissions than targeted for a current period, which can be used in achieving a target to be met in a period to come, or sold to earn profits. The variables that impede banking of emissions are r (advantageous if held in cash but working ill when possessed in the form of emissions permits) and t (to hold emissions permits accrued from immediate reduction efforts works ill because the same reduction efforts should cost less in the future). Conversely, when emissions permits are borrowed from those consumable in a period to come in order to meet an unattained portion of a reduction target for a current period during which few reduction efforts are made actually, r and t act as positive contributors, while p and s become impediments. By the way, s, counted as a net penalty for a delay in time, can be taken as part of the penalty of 1.3 times (5.4%dyear) for a delayed attainment of the first-period (5 years) target agreed at reconvened COP6 (in Bonn, Germany). For example, of the penalty, 5%dyear can be attributed to interest rate (r), and 0.4%dyear to aggravating capacity of sinks (s). But, as far as s is concemed, it is not easy to get it scientifically grounded well enough to yield an intemational accord. It is because forests and oceans are found to have different relations between rising CO2 concentrations and their capacities as sinks. In natural science terms, these involve too complex casual relations to pemfit quantification after all. And yet, they are taken as linear variables here as a matter of convenience (Masayuki Tanaka, 1993). The cost cutting effect ofintertemporal trading has been confirmed by SO2 (sulfur oxide) emissions trading in practice in acid rain control programs under the Clean Air Act of the U.S. (A.D. Ellerman et al 2000). Though not detailed here, most of the cost cutting effect ofintertemporal trading can be explained by analogy with the cost cutting effect of spatial flexibility. Yet, when emissions reductions are put on the x-axis and reduction costff-C (US$) on the y-axis, what's essential is to apply the same yardstick to all costs on the y-axis, which incur in different times. In short, the costs incurring in different times need to be discounted in present values. The question is what discount rate should be set. Simply considering, a discount rate can be identical to interest rate (r). But, as already discussed, intertemporal trading is affected particularly by emissions-permit price rises (p), aggravating capacity of COz sinks (s), and technological advance (t), which means these too should be reflected on a discount rate in present values. Namely, it was thought necessary to reduce the four principal factors (p, r, t, s), influential on intertemporal trading, to present values by a discount rate that takes them into consideration in a composite manner or the so-called composite discount rate, instead of a simple discount rate. What's discussed above is taken as CDR (composite discount rate), and the duration of years to carry out

1187 intertemporal trading as n years. It is p and s that facilitate banking, while r and t pose impediments. relations between CDR and the four factors in the n th year can be expressed as follows:

The

CDRn=(1 +p)" • (1 +s)n/(1+r)~• (1 +t)~=(1+p)~/(1+r)nx(1+s)~/(1+t)~ If the world has the only one energy industry trading emissions permits, the industry is expected to cut emissions and trade emissions permits in a way that such activities yield maximum economic surpluses = maximum profits. When a future is expressed as "total sales of emissions permits (permits price x reduced amount) - total reduction cost (cost/'F-C x reduced amount) = profits (economic surpluses)," the industry should bank when the equations are read now as the right side (RS) > the left side (LS). Similarly, the industry should prefer borrowing when RS < LS is more likely. What affects total sales in the future is Bn=(1 +p)nx(1 +s)n(p determines the price, and s does the size of trade), while what affects total cost in the future is Cn=(1 +r)nx(1 +t)n (r determines cost increases, and t does cost decreases and the magnitude of cost). Accordingly, the world energy industry tries to maximize profits (economic surpluses) (or minimize costs) by banking when the composite discount rate =CDRn=Bn/Cn>I, and by borrowing when Bn/CnI, while borrowing is in advance when CDRn=Bn/Cn 1, or R/+ crop" Retum of a portfolio, R/• Risk free rate, cr : Risk of a portfolio, a" Constant •

(2)

4. In this scenario, we selected the most possible projects by making portfolios, that insured the same risk/return constraints as above. In this sceanario, we also take the Insured CERUPT into consideration.

1236 Namely, we evaluated the total effects of controlling risks by portfolios and the Insured CERUPT.

~Vlilliont-CO2/year) 35

I

BAU

I

INSURED CERUPT

PORTFOLIO

PORTFOLIO+INSURED CERUPT i

Figure 4: Equivalent

CO2

reductions by adopted JI and CDM

CONCLUSIONS

In this paper, we explored efficient institutions to make CDM projects viable. For this purpose, we estimated IRR and other indicators on profitability for 42 projects, taking account of volatilities in CER price and other costs. As a result of Monte Carlo simulations, expected values and their standard deviations in IRR were quantitatively shown. Risks accompanying CDM projects were identified as CER risk, certification risk, baseline risk, and country risk. Although it is difficult to suppress CER risk by diversifying investment into various CDM projects, we could effectively control certification risk, baseline risk or country risks by portfolios of various types of projects in various countries. Therefore, securitization of CDM finance was proposed to facilitate the diversification of investment. Namely, we presented the concept of CDM bond, which is project bond with CER. We also investigated the role of governments to suppress risks in CDM. The institution of the Insured CERUPT was proposed to suppress downside risks in IRR of the projects. Then we evaluated 13 value to assess sensitivity of IRR to increasing rate of CER price. Based on the evaluated value, we explored the most possible combinations in 42 projects, with and without proposed institutions. Evaluated results indicated that the Insured CERUPT and CDM bond could enable us to make CDM projects viable. ACKNOWLEDGEMENTS The author is grateful to Shunsuke Mori, Tetsuo Tezuka, Tsuyoshi Iwama and Junichi Murakami for their useful comments in frequent discussions on CDM. REFERENCES 1. Matsuhashi R. (2002), Investigation of effective institution to make CDM projects viable, paper presented at UNIDO/MRI Forum on CDM and Kyoto Protocol: Opportunities for Japan in Asia 2. Akimoto K., Matsunaga A., Fujii Y., Yamaji K. (1998) Game theoretic analysis for Carbon Emission Permits Trading among Multiple World Regions with an Optimizing Global Energy Model (in Japanese). Transactions of Japan Institute of Electrical Engineers 118-C, p 1424 3. Matsuhashi R., Yoshida ¥., Fujisawa S., Momobayashi ¥., Ishitani H.(2002), Investigation of institutions for making CDM viable, Proceedings of 21th annual meeting on energy resource, p541-546

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1237

ECONOMIC AND G R E E N H O U S E GAS EMISSIONS ASSESSMENT OF EXCESS BIOMASS E X T R A C T E D FROM FUTURE KRAFT PULP MILLS A. Adahl, S. Harvey and T. Bemtsson Department of Heat and Power Technology, Chalmers University of Technology, 412 96 Grteborg, Sweden.

ABSTRACT Different studies have shown that the process heat requirements of future pulp mills can be satisfied using available internal biomass (bark and lignin), which are process by-products. Assuming that biomass is CO2 neutral, further reducing the process heat demand will not therefore lead to further reduction of Greenhouse Gas (GHG) emissions - unless the excess biomass is extracted and used elsewhere to substitute fossil fuels. Previous work has demonstrated the potential to extract and export significant amounts of biofuel from future pulp mills. The associated extraction costs can be competitive with conventional forest fuels. However, biofuel extraction reduces the mill's potential to cogenerate electric power. This reduced power output must be compensated by increased purchased power from the grid, with associated costs and emissions. Such emissions must be affected to the extracted biofuel, which cannot therefore be considered as CO2 neutral. This paper presents results for costs and associated greenhouse gas emissions for excess biofuel extracted from a pulp mill. The results show that the extraction costs are competitive, but that the greenhouse gas emissions associated with the exported biofuel can be significant and must therefore not be neglected.

INTRODUCTION

Biofuel prices have begun to increase in Sweden [ 1], as a result of increased demand resulting from energy and environmental policy instruments [2]. Similarly, EU policy [3] aims at increasing usage of biomass as a renewable fuel. To develop future sustainable energy systems with low greenhouse gas (GHG) emissions, it is necessary to not only increase use ofbiofuels, but also to use such fuels as efficiently as possible. Swedish kraft pulp mills currently use oil and intemal biofuels to satisfy process heat demands. The Swedish "EcoCyclic Pulp Mill" project has defined the energy system for a reference mill incorporating best available technology [4]. According to this project, future pulp mills should not only be energy selfsufficient using internal biofuel resources, but should also be able to export excess bark and lignin [5, 6]. Internal biofuels are pulp process by-products, and the total production costs for biofuel extraction can be computed based on costs for process integration measures to reduce the mill heat demand (and thereby the process biofuel consumption), biofuel processing costs, and changes in electric power costs since decreasing the mill steam demand decreases the amount of electric power that can be cogenerated. Furthermore, biofuels are generally assumed to be CO2 neutral ~ due to the closed carbon cycle. However, given the above I Other sources of GHG emissions associated with biofuel usage include for example harvesting and transportation. Land use practises can also impact net GHG emissions for biofuels. These aspects are not further considered in this study, since these emissions are assumed to be charged to the pulping process.

1238 mentioned changes to the mill steam and power balances resulting from biofuel extraction, the exported biofuel should not be considered as CO2 neutral, but should rather be charged with the emissions associated with the extraction process. The aim of this paper is to assess costs and global GHG emissions associated with biofuel extracted from a future pulp mill. The paper presents a case study based upon a Swedish kraft pulp mill. Identifying potential energy efficiency measures for retrofitting of a pulp plant requires the use of appropriate tools. The measures considered in this paper were identified in previous work at the authors' department using process integration tools, including both traditional pinch technology tools [7, 8] and advanced tools specially suited to retrofit situations [9, 10]. A description of appropriate tools for systematic analysis of GHG emissions associated with process integration measures may be found in [ 11 ] and [ 12].

CASE STUDY PULP M I L L PLANT CHARACTERISTICS The pulp mill studied in this paper is a Swedish combined pulp and board mill producing 530,000 tonnes/year of board based on both CTMP and sulphate pulp. The current mill heat demand is 195 MW. Electricity is cogenerated for on-site use. Additional power is purchased from the grid. Effluents from part of the plant are currently discharged to an aerated pond. New environmental restrictions require that the load on the pond be decreased. In order to treat the effluent stream its concentration must first be increased in a pre-evaporator. Conventional pre-evaporation increases the mill steam consumption. Alternatively, process excess heat identified by pinch technology could be used as a heat source. In previous work at the authors' department [ 13], excess heat suitable for effluent pre-evaporation has been identified at three temperature levels. The excess heat could also be used as heat source to generate additional steam by heat pumping, thus reducing the boiler fuel consumption. Three alternative process integration measures were therefore investigated for decreasing boiler steam consumption to drive the pre-evaporation process, namely: (I) heat pumping of low temperature mill excess heat; (II) recovery of mill excess heat; (III) use of recovered mill excess heat in combination with heat pumping. Based on available process stream data and heat pump characteristics, the potential for delivered heat from the heat pump was estimated to be 5 MW, using a conventional mechanical vapour recompression (MVR) heat pump. The three alternative solutions are analysed with the conventional steam solution as baseline (reference). Table 1 summarises the key data for the analysis. The reference situation requires an increase of biofuel consumption in order to meet the increased steam demand of 18.6 MW. Alternative III decreases the plant's steam demand by 22.1 MW compared to the reference, i.e. not only the pre-evaporator unit can be run using waste heat only, but steam from the MVR heat pump can be used to reduce the boiler steam demand for other parts of the mill. The potential for biofuel export from the mill was estimated based on the following assumptions: -

Oil is not used as a fuel at the mill, i.e. a reduction of steam demand (compared to the reference) leads to a corresponding potential for biofuel export, adjusted for conversion efficiencies; Extracted biofuel may be in the form of bark or lignin. Energy requirements and emissions associated with further processing and transporting of the extracted biofuel are not considered; The biofuel boiler efficiency is set at 0.85, based on the fuel lower heating value; The changes in cogenerated electric power associated with changes in mill steam demand are estimated based on the mill's steam turbine operating curves [ 14]. The mill operates 8760 hrs/year, including the cogeneration unit. Although current electricity prices in Scandinavia do not justify year round cogeneration, a number of studies (e.g. [15]) indicate a clear need for increased base-load (year-round) power generation in the near future.

1239

TABLE 1 DATA FOR RETROFIT ALTERNATIVES

Retrofit Measures

Process data Decreased Number of presteam demand evaporator w.r.t, reference units

[MW]

Ref I

II III

Pre-evaporator heat source (BS=Boiler Steam) Boiler steam only BS + Heat pumping of excess heat BS + Excess heat Excess heat and heat pumping

Investment data Heat Rearrangements for evaporator pump heat pump [MSEK] [MSEK] [MSEK] Pre-

Results Extracted biofuel [GWh/year]

Increased power from

~d [GWh/year]

76.6

0

0

0

0

5.0

76.6

5.52

4.6

64

15.7

9

17.1

110

0

0

221

38.7

9

22.1

110

5.52

4.6

286

54.6

4

A S S E S S M E N T OF E X T R A C T I O N C O S T S A N D A S S O C I A T E D G H G E M I S S I O N S

Three alternative energy saving measures are investigated for the pulp mill, as discussed in the previous section. The baseline chosen is conventional live steam pre-evaporation for the pulp mill. The biofuel released from the pulp mill is considered as a by-product of the pulping process, i.e. LCA GHG emission values associated with biomass harvesting and transportation together with biomass raw material costs are allocated to the pulping process and not to the by-products. Biofuel extraction costs are therefore constituted by investment costs to reduce the boiler steam demand (see Table 1) plus increased grid power purchase costs due to the decreased potential for mill-site cogeneration (Table 1 presents the estimated increase in power purchases from the grid). Extracted biofuel processing costs (e.g. drying and pelletising) are not considered in this study. Capital costs are annualised using the annuity method with a capital recovery factor of 0.2 (except for the heat pump where 0.42 is used, reflecting the demand for a shorter payback period for this type of equipment). As discussed previously, the different measures considered affect the pulp mill electric power balance, and additional power must be purchased from the grid (see Table 1). The GHG emissions associated with the additional power generated by the grid must be allocated to the extracted biofuel. Three levels of electricity grid emissions are considered (Table 2), reflecting uncertainty about the evolution of the power system mix of technologies, and about the corresponding choice of baseline for calculations. Two levels of electricity prices are considered. The low value reflects the current situation in Scandinavia, with low power prices due to market deregulation and relative abundance of low-cost generation capacity. The higher value reflects a future situation where it is assumed that the power price is set by the generation costs of new natural gas fired combined cycle plants (NGCC).

TABLE 2 ELECTRICITY GRID SCENARIOS Electricity price on the Nordic power market (SEK/MWh) 150 300

Electricity grid GHG emissions (kg/MWhe0 110

300

380

150 300

890

Corresponding electricity production in the future deregulated Northern European electricity market Average Nordic power system based on hydropower, nuclear power and fossil fuel power plants Natural gas combined cycle (NGCC) power generation as marginal production technology Coal-fired steam turbine power plants as marginal production technology

1240 RESULTS Figure 2 shows the results for biofuel specific extraction costs resulting from the considered pulp preevaporation plant retrofit measures. For comparisons, the figure also shows the current Swedish market price for bark and other wood-waste fuels taken from [ 1]. The market price for premium forest fuels is higher, but in this study it is assumed that the biofuel extracted is bark or lignin. Due to uncertainty regarding the attractiveness of lignin on the biofuel market, it is assumed in the study that this type of fuel has the same market value as bark. In order to motivate such an investment, the biofuel extraction costs must clearly be lower than the market value for the extracted biofuel. As shown in the figure, the specific extraction costs vary for the different pulp mill measures considered. The market electricity price also has a significant impact on the extraction costs. Regardless of the electricity price, the extraction costs associated with Measure I is higher than the market value of the biofuel. For the lower electricity price, Measures II and III are competitive, whereas for the higher electricity price, only Measure II is competitive. The figure also shows that if biofuel market prices increase in the future, all three measures are likely to be competitive, even with future high electricity prices. 160

•,-'

ca

Current biofuel

140

market:~ce:

O

u _~ 120 o ~ lOO

90 SEWMWh

C

I Low electricity market pdce

"~w O

m

I High electricity market price

20 I

II Measures

III

Figure 2: Biofuel specific extraction costs associated with process integration measures at the pulp mill (Note: extraction costs include annualised investment costs plus electricity costs due to changes to the site power balance) It should also be noted that Figure 2 presents specific biofuel extraction costs. The total investment depends on the amount extracted (see Table 1). Measure I corresponds to a relatively low biofuel extraction potential (64 GWh/yr.) at a relatively high specific extraction costs. Measures II and III correspond to a significantly higher extraction potential (221 resp. 286 GWh/yr.) at significantly lower specific extraction costs. Figure 3 presents results for global CO2 emissions increase for all retrofit measures, compared to the reference boiler steam driven pre-evaporators. The results are presented as specific emissions per unit extracted biofuel. The key values from Figures 2 and 3 are presented in Table 3. Three levels of emissions associated with grid electric power generation are considered (see Table 2) for assessing the impact on global GHG emissions associated with changes to the pulp mill net power balance. For comparison purposes, the figure includes reference values typically used in LCA assessment studies for GHG emissions for three types of fuels, namely oil, natural gas and virgin forest fuel. The results presented in Figure 2 showed that electric power prices have a significant impact on specific extraction costs. Figure 3 shows that the impact of grid emissions is even more significant. From a GHG emissions perspective, extracted biofuel is only comparable to virgin forest biofuel only when grid emissions are low. If grid emissions are high, the GHG emissions associated with the released biofuel are somewhat lower than natural gas GHG emissions, but clearly much higher than for virgin forest biofuels.

1241

• I=

3001 iiiiiiiiiiiiiiiiiiiiiiiiiiiiiiiii~~~i~iiii~-NaturOil-~~--al~// 250,

CorroarableLCA I 002 errission values

.9

w ~,-,. 200

• Low electricity grid

E~ e~ 0

150

emissions

tO o ~ ol _.u ~ 100

Virginforest biofuel(bark)

o Q.

[] Intermediate electricitygrid emissions

[] High electricity grid

o I

u

III

emissions

Measure

Figure 3: Global

CO2

emissions associated with extracted biofuel

TABLE 3 SUMMARY OF BIOFUEL EXTRACTION COSTS AND SPECIFIC CO2 EMISSIONS

Measures at the pulp mill 1 [I I

Electricitymarketprice (SEK) 150 300

Biofuel extractioncost (SEK/MWhfuel)

Electricitygrid emissions (ks/MWh¢,) ll0 380 890

Specific C O 2 emissions

(kg/MWhfuel)

103 139

56.5 82.8

16.2 81.7 206

8.76 56.1 145

I I

67.0 95.6 10.5 62.0 159

DISCUSSIONS As pulp mills become more energy efficient, there is an increasing potential export of excess biofuel from this industry. The goal of this paper was to investigate costs and associated GHG emissions for extracted excess biofuel, based on results from a case study that investigated technical and economic opportunities for excess heat utilisation in a Swedish pulp and board mill. The study accounts for costs and emissions resulting from changes in the mill's electric power balance. The results show that for the case study considered, excess biofuel can be extracted at costs that are often competitive compared with the market value of the extracted fuel. The extraction costs are significantly higher when the economic value of the loss of cogenerated power is high. As the demand for biofuels increases in the future, there is therefore a clear incentive to further investigate extraction of excess biofuel from pulp mills. This may be seen as a business opportunity by the industry itself, or alternatively it may be seen as an opportunity for external investors wishing to invest in a secure source of low-cost biofuel. Jointventure strategies involving both mills and external market actors may also be attractive. International investors may become interested in the Swedish pulp mill biofuel surplus potential, under the terms of the joint implementation mechanism provided for in the Kyoto protocol. Swedish biofuel could thereby be used for e.g. fossil fuel substitution in biofuel-deficient areas of Europe. This study however shows that, unlike virgin forest biofuels, extracted biofuels can have relatively high associated emissions (in certain cases close to the emissions levels of natural gas), depending on the

1242 reference grid emissions associated with electric power generation. In order to achieve global greenhouse gas reductions, biofuel must clearly be used for substitution of fossil fuels. Furthermore, given the GHG emissions associated with excess biofuels extracted from pulp mills, these fuels must be used to be used to increase usage ofbiofuels, and should not compete with virgin forest biofuels, as discussed in [ 16]. In order to assess the cost-effectiveness of extracting excess biofuel from pulp mills as a means to reduce global greenhouse gas emissions, it is clearly important to include the final usage of the extracted biofuel in the analysis. Furthermore, the results of this study show that the specific extraction costs are dependent on both the nature of the energy-efficiency measures implemented in order to release the excess biofuel, and on the economic value of the cogenerated electric power. Thus, the cost-effectiveness of greenhouse gas emissions reduction based on extraction of excess biofuel from pulp mills and usage of this biofuel to substitute fossil fuels requires a detailed analysis adopting a suitable system perspective so as to account for all major effects. Results from this type of study must be used as input for such an analysis.

REFERENCES

.

9. 10. 11. 12. 13. 14.

15. 16.

The Swedish Energy Agency. (2002). Prisblad fOr biobriinslen, torv mm. Nr 2/2002, www.stem.se. The Swedish Government. (2002). Energipropositionen 2002, www.regeringen.se. The EU Commission of the European Communities, Commission Staff Working Paper (2001). Third Communication from the European Community under the UN Framework Convention on Climate Change, www.europa.eu.int. STFI. (2000). Final report KAM 1, 1996-1999, Report A32. STFI, Stockholm, Sweden. Wising, U. (2001). Licentiate Thesis, Chalmers University of Technology, Sweden. Algehed, J. (2002). PhD Thesis, Chalmers University of Technology, Sweden. Linnhoff, B e t al. (1994). User's Guide on Process Integration for the Efficient Use of Energy. IChemE, Rugby, UK. Linnhoff, B. (1994). Chem. Eng. Progress, Vol. 90, No. 8, 32-57. Carlsson, .A., Franck, P.-A., and Bemtsson, T. (1993). Chemical Eng. Progr. Vol 89 (3), pp 87-96. Nordman, R., and Bemtsson, T. (2001). Canadian Jnl of Chem. Eng. Vol 79 (4), pp 655-662. Axelsson, H., Asblad, A., and, Bemtsson, T. (1999). Applied Thermal Eng., Vol. 17, 993-1003. Adahl A., Harvey S. and, Berntsson T. (2000). ECOS 2000 proceedings, Eurotherm Seminar 65. 2000;(3): 1213-1224. Bengtsson, C., Nordman, R. and, Berntsson, T. (2002). Applied Thermal Eng., Vol. 22, 1069-1081. Bengtsson, C., and Karlsson, M. (1999). Co-operation of the MIND-method and the Pinch Technology - energy efficient pre-evaporation of bleach plant filtrate using waste heat. Report nr 4, ISSN 1403-8307, Program Energisystem, Link6ping University, Sweden. Energimyndigheten. (2001). Liiget p& den Nordeuropeiska elmarknaden - ett fdrsOk till en problemorienterad analys. Report nr ER23:2001 ISSN 1403-1892, Eskilstuna, Sweden. Energimydnigheten. (2001). Underlag for m&lformulering for L&ngsiktiga avtal med energiintensiv industri. App. 3 in N~ringsdepartementet report Ds 2001:65, Fritzes, Stockholm.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1243

TRANSPORTATION, CDM, AND GHG EMISSION REDUCTIONS Ming Yang (PhD) 1 and Xin Yu (PhD Candidate) 2 ~Energy Economics and Technology, 12 Kiah Street, Glen Waverley, Victoria, Australia, email [email protected] 2Department of Management, Monash University, Australia, Email: [email protected]

ABSTRACT This paper aims at presenting information on how transport technology, management and clean development mechanism (CDM) facilitate GHG emission reductions in urban passenger transport. Efficiency factors of urban passenger vehicles are analysed. Emissions from various transportation fuels and vehicles are demonstrated. The paper also shows two case studies about the impact of transportation planning and CNG motor vehicles on a cleaner city environment. Then, this paper briefly introduces the CDM of the United Nations Framework for Climate Change Convention (UNFCCC) and describes how CDM will leverage additional financial resources from Annex B parties to the developing countries. This paper concludes that governments in developing countries have various opportunities to mitigate climate change, and that integrated transportation planning and clean transport technology combined with clean development mechanism will assist government decision makers of the developing countries to better develop their transportation systems.

INTRODUCTION Of all human activities, driving motor vehicles produces the most intensive CO2 emissions and other toxic gases per capita. A single tank of gasoline releases 140 ---180 kilograms of CO2. Yang [ 1] indicated that over 25% of transportation-related GHG emissions originate from urban passenger travel. Throughout major cities in Asian developing countries, unsustainable trends in urban transportation have already been manifested as frequent congestions, periodic gridlock, a lack of funds for desired road rehabilitation and maintenance, and evidence linking respiratory illnesses and deaths to poor air quality. Many city governments in developing Asian countries still have opportunities to make things better. In Hanoi and Ho Chi Minh City in Vietnam, for example, urban passenger transportation is currently dominated by motorbikes. The city governments are about to develop buses. With the development of the Vietnamese economy, people would shift from motorbikes to cars. Two options, i.e. private or mass public transportation modes are facing Vietnam. Urban passenger travel presents unique challenges and opportunities if it is to contribute towards achieving GHG emission reductions. Private cars and motorbikes, often with only a single occupant, dominate a Contact by December 2003: Efficiency Adviser, Asian Development Bank, 6 ADB Avenue, Mandaluyong City, 0401 Metro Manila, The Philippines, email: mvan~(~,adb.ore. However, the viewpoints expressed in this article are solely those of the authors, and they do not represent those of the Asian Development Bank

1244 personal travel. However, compressed natural gas (CNG) vehicles release about one quarter less gasoline vehicles. Some of other noxious emissions are even less than this ratio.

C02

than

This paper presents emissions from various transportation fuels and vehicles, and shows city governments how to initiate economically sustainable and environmentally-friendly transportation modes by two case studies in China. In addition, the paper demonstrates how to access additional capital investment in transport sector via CDM from the developed countries to support sustainable development in developing countries. This paper is descriptive and experimental rather than academic research. It may interest policy makers in developing countries, who are less aware of climate change and urban passenger transportation efficiency. This paper will help them better understand how to reduce GHG emissions and local pollutions in developing their urban transportation systems.

V E H I C L E EFFICIENCY FACTORS Vehicles efficiency factors vary on the basis of different assumptions and methodologies. Generally speaking, buses are the most energy and GHG-emission intensive in per v e h i c l e - 1 0 0 km travel; but motorbikes and cars are the most intensive in terms of per-person per 100 km traveled. See Figure 1.

10

60 -[ ............................................................. 50 I

Gasoline and Diesel buses

°,0 iiiii 3o~

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.

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.

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iiiiii .

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..............................................................

9 J- - = ~ . ,

Gasoline motorcycle

~

6

......

.......

R

5

...... *--

3

...............................................................

Gasoline car

.

Diesel car, Gasoline car & Gasoline

• ......................................

"i 20 ] . . . . . . . . . . . . . . . . . . . . . . . . . . . .m_ot.orcycle. .............................. "'i

J

10 ~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ~ - " ....... m-----'----m~m-,, --m 0

2

Gasoline and Diesel buses ...... ~, ............. ~ .......... - ~ ............. ~ .......

I

...........................................................

0 1990

1995

2010

2020

1990

1995

2010

2020

Source. Adopted and revisedfrom [2]

Figure 1: Average Fuel Efficiency Factors for Urban Travel (Canada)

The left hand chart in Figure 1 shows the energy intensity of buses, cars and motorbikes in Canada in 1999. Gasoline and diesel buses rank the highest in the range of 40 to 50 liters per 100 km traveled. The least energy intensive vehicle is the motorbike, consuming less than 10 liters per 100 km. Diesel and gasoline cars burn about 10 to 20 liters per 100 kin. However, in terms of per-person kilometer traveled, the order of energy intensities is reversed. The right hand chart of Figure 1 shows the energy intensity in liters per person per 100 km. We assume that all the vehicles are half loaded, i.e., 25 people for a bus, 2.5 for a car and one person for a motorbike. Then, energy intensity range order will be inverted when compared with the case in the left chart. The gasoline motorbike requires 7-9 liters per person-100 km travel, but a bus rider consumes no more than 2 liters. Diesel and gasoline cars are in the range between 4 to 7 liters per person- 100km. In Asia, mass transportation will be more efficient than the scenario described in the right chart, because buses in Asia are usually more than half-loaded and cars are less than half-loaded.

1245 EMISSIONS FROM FUELS TABLE 1 shows the weighted GHG emissions in moles of CO2 equivalent per vehicle-mile traveled (VMT) which is equal to the un-weighted quantity multiplied by the global warming potential per mole of each gas, relative to carbon dioxide. One can see that compressed natural gas (CNG) and liquefied petroleum gas (LPG) vehicles emit least GHGs among all the transportation fuels and alternatives. TABLE 1 WEIGHTED MISSIONS FROM FOSSIL FUELS (Unit: Moles of CO2eq per VMT (Weighted) Greenhouse Gas

Gasoline

Diesel

Compressed Natural Gas

Liquefied Petroleum Gas

Carbon Dioxide (C02)

7.9

7.88

5.64

Methane (CH4)

0.22

0.22

0.91

0.17

Nitrous Oxide (N20)

0.54

0.54

0.54

0.54

Nitrogen Oxides (NOx) CarbonMonoxide (CO)

1.06

1.06

0.99

0.99

0.97 0.97

0.92 0.98

Total

10.71

10.68

9.03

8.61

Source: Wang [3] a n d USEIA [4]; Note: one Mole contains 6.023 x 10e3 molecules or atoms

The above two sections show that buses are the most energy efficiency mode among all transportation means in terms of person-km traveled, and that CNG and LPG are the least carbon emitting fuels per vehicle mile traveled (VMT) if the fuels' GHG emissions are calculated in weighted moles. We would conclude that CNG and LPG buses are one of the best modes in urban passenger transportation. This argument is also supported by two case studies in China.

CASE STUDY 1: INTEGRATED TRANSPORTATION PLANNING IN XIAMEN A project was undertaken in 1997 aiming at solving the traffic congestion and air pollution problems in Xiamen by an integrated transportation planning. The project team analyzed policies adopted by the Xiamen municipal government to improve the transportation conditions and air quality. A detailed description of the project is available in Yang [ 1]. In the following, we present the key results of the study. Eight main components in the Xiamen's integrated transportation planning are presented: 1. Deciding system boundary; 2. Forecasting transportation demand; 3. Integrating all possible elements related to transportation system focusing on mass transportation and CNG vehicles; 4. Using access not just mobility; 5. Designing alternative scenarios; 6. Using linear programming model to carry out system optimization; 7. Evaluating planning results; and 8. Implementing the plan. Figure 2 shows the relationships and steps of the components. The following measures were adopted by the Xiamen municipal government to reduce vehicle transportation demand: 1. Improve the city outline plan for new city development zones. Tourism industrial facilities, commercial and entertainment facilities, schools and hospitals will be developed in each zone; 2. Design special transportation means for residential areas, where large trucks are not allowed to enter; 3. Focus on public transport development and establish alternative modes of transport. These include: pavement; bicycle lanes; bus lanes; high-occupancy vehicle lanes; integrate system with trains, bus and bicycles; pricing measures; and market based parking measures; 4. Leave lee-ways in road planning; 5. Build express roads across the city and high way around the city; 6. Reduce the number of one-way streets and roads; 7. Towing system should be pout into operation in the main roads of the city; 8. Adopt special

1246 policies to attract investment in transportation infrastructure, levy fuel consumption taxes and inspect vehicles regularly; 9.Levy high penalty on those whose vehicle tail gas does not meet the standards; 10.Construct parking lots with the development of new roads and buildings; and 11. Develop high efficiency and least carbon emission vehicle technologies in the city.

Decide S~tem

Design systemscemrios

Boundary lb. v

IVk~polilnnhegi~ Tmnsl:ortsyslem Demandforecesting Ton-kndpezson-tri~ In~gm~all p~s~le elements Iamd/EdtEalim/Imlm-triW/ commerciW...

InlegmtetminsJbusesfoic~les

~ast costoptimizafions Li~r Pmgm_mmodel

Planningresulte~luation

O~inionof stakeholders

Access mtjlmtmobility Pho~ linterr~tlm~lsl ml~tmr~...

Figure 2: Methodological Framework for Integrated Transportation Planning

CASE STUDY 2 - COMPRESSED NATURAL GAS VEHICLES IN BEIJING In 1995 in Beijing, 800,000 vehicles daily produced an estimated 24,000 tons of CO1, 320 tons of hydrocarbons, 12 tons of oxides of nitrogen (NOx), 67 tons of non-methanol carbide, 24 kilograms of benzene and lead Guo [5]. The Beijing Municipal government manages about 70,000 fleet vehicles, 10% of total vehicles in Beijing in 1996. These fleet vehicles include buses, taxies, post trucks, and the trucks used by environmental and sanitary sectors and by Beijing transportation companies. A project team funded by the USEPA worked with North China Vehicle Research Institute, which would be willing to invest in gas filling station development and importing retrofitting technology from New Zealand. Detailed information on the project is available in Yang [6]. In the following, we briefly present the results: 1. 350 gas filling stations are needed in Beijing, and each feeds 200 at 500 M3/hr; 2. Using New Zealand (NZ) CNG Vehicle technologies to reduce conversion investment; 3. Comparing the NZ CNG vehicles with gasoline vehicles in Beijing: (1) CO reduced by 97%; (2) Hydro-carbon reduced by 72%; (3) NOx reduced by 39%; and (4) CO2 reduced by 25%; 4. GHG emission reduction for one gas fill station (for 200 vehicles) is about 39,000 tons of CO2 per year. Since 1997, CNG vehicles have been developing very quickly in Beijing. About one third of the city buses weas run by CNG engines in Beijing by September 20011.

i Source:Author's on-site surveyin Beijing in September2001.

1247 CDM FACILITATES CLEAN TRANSPORT

Clean Development Mechanism (CDM) is a modified version of Joint Implementation that was included in the Kyoto Protocol for project-based activities in developing countries. In Article 12.2 of the Protocol, the parties established the CDM for the purposes of assisting developing countries in achieving sustainable development and helping Annex B parties meet their emissions limitation and reduction obligations. Under the supervision of an Executive Board of CDM, private and public funds may be channeled through this mechanism to finance projects in developing countries. With CDM, countries co-operate in an emissions mitigation project in a developing country with the donor country acquiring the Certified Emission Reduction Units generated by the project while the host country benefits from the contribution of the project to sustainable economic development through investment in environmentally sound technologies. It is estimated that US$ 1.2 billion will be transferred as CDM funds from Annex B countries to the developing countries each year during the next decade. In the following, as an example, we present the willingness to pay of the government of Netherlands as a simple example of the funding source. Under the Kyoto Protocol the Dutch obligation is to reduce its GHG (green house gases) emissions by 6%, compared to the reference year 1990. Already in 1999 the Dutch government decided to score 50% of this obligation on a national level and the remaining 50% (125 million tonnes of CO2) abroad by application of the Flexible Mechanisms CDM, JI (Joint Implementation) and IET (International Emissions Trading) CERtYPT [7]. The government of Netherlands also is willing to pay the CER at the price of about US$ 4. See TABLE 2. If the Netherlands acquires the 125 million of CERs by CDM, the total funding source from the Netherlands will be about US$ 600 million. TABLE 2 WILLINGNESS TO PAY CO2 CREDIT BY THE NETHERLANDS GOVERNMENT CDM Projects Renewables energy (excluding biomass): Energy production by using clean, sustainable grown biomass (excluding waste) Enerb,y efficiency improvement Others, among which fossil fuel switch and methane recovery

Prices EUR 5.5 US$ 4.8 EUR: 4.4 US$ 3.8 EUR: 4.4 EUR 3.3

US$ 3.8 US $ 2.9

Source: CERUPT [8]; Note to exchange rate: On Feb 15, 2002, 1 EUR = 0.873 US$, Source: http ://goeurope.about. com/gi/dynamic/offsite.htm, 9site=http%3A %2F°/~2Fwww.x-rates.com%2 F

POSSIBLE CDM TRANSPORT PROJECT EXAMPLES IN ASIA

Substitution of passenger buses for motorbikes in main cities of Vietnam In Hanoi and Ho Chi Minh City, motorbikes are currently dominant in passenger transportation. As indicated early in this article, motorbikes are one of the most energy and GHG intensive means of transportation. Mass transportation system does barely exist in the two cities. If the city governments would develop mass transportation, CNG buses for instance, it will definitely benefit global and local environment conservation. Developing mass transportation needs to be well planned. Without a good plan, bus and train system may not be able to work due to traffic congestions. The development of bus lanes, regulations on the use and registration of motorbikes should go hand in hand. Consequently, an integrated transportation planning, followed by government policy and regulations on vehicle uses, and implementation of mass clean fuel vehicle development may be good steps for the municipal governments in Vietnam to adopt.

1248

CNG vehicle promotion in Bangladesh Bangladesh is rich in natural gas resources but short of petroleum supply. In 2000, Bangladesh imported about 58,400 barrels of oil per day [9]. Developing CNG vehicles will not only benefit environment, but also reduce burden of foreign currency expenditure. The government of Bangladesh is preparing to convert and replace about 100 thousand petrol and diesel vehicles with CNG vehicles. Evidently, CDM will add extra benefits to the CNG project and make the project financially and economically viable.

CONCLUSIONS

A survey shows that transportation modes from most energy efficient one to least efficient one are: buses, cares and motorbikes. Furthermore, CNG and LPG vehicles are the least emission technologies so far. We would say that developing CNG buses is one of the best options to promote environmental friendly urban passenger transportation for those countries where domestic natural gas resources are available. Two case studies show that the substitution of CNG vehicles for petrol or diesel vehicles will not mitigate GHG emissions but also benefit local pollution reductions. Government policies and regulations should have a good transport plan, encourage the use of mass transportation and discourage the use of private cars and motorbikes. CDM will facilitate advanced technology and fund transfer from the developed countries to the developing countries. It may change some financially distractive projects into attractive ones. Future CDM projects in Asia may include the substitution of CNG buses for motorbikes in major cities in Vietnam and CNG vehicle development in Bangladesh. CNG vehicles and CDM are motoring towards cleaner cities in Asia.

REFERENCES

Yang M., (1998) Transportation and Environment in Xiamen, Transportation Research D, Elsevier, UK, Vol. 3, No. 5, pp. 297-307. Hagler Bailly (1999), Strategies to Reduce GHG Emissions from Passenger Transportation in Urban Canada, Final report for National Climate Change Process, Transportation Table Passenger (Urban) Sub-group, Toronto Ontario. Wang M. (1995) Measurement of Emissions: Greenhouse Gas Estimates for Alternative Transportation Fuels, Unpublished final report prepared for the Energy Information Administration, Vienna, VA, December. USEIA (1993), Emissions of Greenhouse Gases in the United States 1985-1990, DOE/EIA-0573, Washington CD, September, p 15. Guo X. Y. (1996) Pre-feasibility of Developing Compressed Natural Gas Automobiles in Beijing, China North Vehicle Research Institute, Beijing Yang M.. Kraft-Oliver T., Guo X. Y. and Wang T. M. (1997), Compressed Natural Gas Vehicles Motoring Towards a Cleaner Beo'ing; Applied Energy, Elsevier, UK, Vol. 56, Nos. ¾, pp, 395-405. CERUPT (2001), Implementation of the Clean Development Mechanism by the Netherlands, Ministry of VROM, Netherlands. CERUPT (2001) Terms of Reference for CDM project development, Ministry of VROM, Netherlands. USDOE (2001), http://www.eia.doe.gov/emeu/cabs/bangla.html

NON-CO2 GASES

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1251

AN ASSESSMENT OF THE ABATEMENT OPTIONS AND COSTS FOR REDUCING THE EMISSIONS OF THE ENGINEERED CHEMICALS J. Hamisch l, J. Gale2, David de Jager 1 and Ole Stobbe l IECOFYS energy & environment, Eupener Str. 59, 50933 Cologne, Germany 2IEA GHG Programme, Stoke Orchard, Cheltenham, Gloucestershire, GL52 7RZ, UK

ABSTRACT

This work assesses the contribution to climate change resulting from emissions of the group of halogenated greenhouse gases. A bottom-up emission model covering 22 technological sectors in four major regions is described. For annual emissions of HFCs, PFCs and SF6 which are regulated under the Kyoto Protocol the relative contribution is projected to increase to 2% (600 MT CO2 eq.) of global greenhouse gas emissions by 2010. This trend is expected to continue, emissions are projected to grow to a contribution of roughly 3% (870 MT CO2 eq.) in 2020 compared to 0.9% (300 MT CO2 eq.) in 1996. For HFCs, PFCs and SF6 this study identifies global emission reduction potentials of 260 MT CO2 eq. per year in 2010 and 640 MT CO2 eq. per year in 2020 at below US$50 per ton. These values correspond to roughly 40% and 75% of projected emissions in 2010 and 2020, respectively. INTRODUCTION

This study covers the radiative impact of the following compounds: chlorofluorocarbons (CFCs), hydrochlorofluorocarbons (HCFCs), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), sulfur hexafluoride (SF6), halons and methyl bromide. For decades, these synthetic halocarbons have been widely used e.g. as refrigerants, blowing agents in foam production, propellants for aerosol applications, solvents, surfactants and fire-fighting. The non-ozone-depleting HFCs are progressively substituting CFCs and HCFCs in many of their applications, leading to rapidly growing emissions rates of HFCs. For this reason, and because of their atmospheric persistence, they have been included into the Kyoto-Protocol. PFCs and SF6 have also been included for the same reasons. Reilly et al. [ 1] have shown that a failure to control the growth of emissions of these gases can significantly increase the costs of compliance with the Kyoto Protocol as additional CO2 reductions have to be achieved in other sectors (such as power sector) to compensate for this growth. The direct global warming potentials I (GWP) of these gases range from a few hundred to more than 20,000 times CO2-equivalent, when calculated over a 100-year period [2]. Within the stratosphere, the chlorinated and brominated compounds are the prime causes of ozone depletion. This contribution to ozone depletion adds an indirect cooling to the radiative effect of these compounds. In the case of the so-called halons (bromofluorocarbons) and methyl bromide this indirect cooling effect by far outweighs the direct effect. The uncertainties associated with net global warming impact of these compounds are large [2, 3, 4]. In this study, the average ! Reportedas

C O 2 equivalents(CO2 eq.) based on the IPCC (2001) [4] globalwarmingpotentials(100 year period).

1252 value of the maximum and the minimum net-GWPs is used as the default GWP value for the ODS. THE M O D E L AND DERIVED SCENARIOS

The economic evaluation required a dynamic and detailed bottom-up emission model to connect emission projections to reduction options and associated costs. The current knowledge of emission levels for the gases is still fairly limited. There is virtually no database or emission model that would provide a consistent coverage for more than a few compounds. Neither do most existing emission inventories allow projections of future emission levels. Therefore, it was decided to develop an emission model for this study in order to have a consistent and transparent coverage of an extended number of emission sources from various sectors. The model was built for use in comparative mitigation assessments and not for applications in atmospheric sciences. It thus did not need to have a high spatial or temporal resolution or produce emission data for each individual species. Its main strength is a consistent link between past and future emission levels. The model provides a reasonable representation of different technological sectors, a technology oriented link between emission levels and abatement options and - last but not least a high degree of flexibility for modification of sector specific data like emission factors, growth rates, GWP data and alike. Fundamentally, the temporal evolution of emissions in this model is calculated as the product of an emission factor and a technological activity. Both are generally assumed to be time- dependent: the former due to "incremental" technological change (e.g. improved containment of refrigerant) and the latter through economic growth (e.g. increasing demand for domestic refrigeration) or major shifts between technologies (e.g. the switch between different classes of refrigerants). The emission model which was created for this study builds on the experience gained for a recent study for the European Commission [5]. It covers 22 different sub-sectors that contribute to emissions of the halogenated compounds covered by this study. These sub sectors include; commercial refrigeration, cold storage and food processing, industrial refrigeration, stationary air conditioning and heat pumps, transport refrigeration (road, rail, ship), heat pumps (for heating only), domestic and small commercial (hermetic) refrigeration, mobile air conditioning, extruded polystyrene (XPS), polyurethane (including one component foams), polyisocyanurate and phenolics, solvents, metered dose inhalers (MDI), technical aerosols, by-product emissions of HFC-23, primary aluminium production, semiconductor production, magnesium production, use of gas insulated switch gear, manufacture of gas insulated switch gear, fire-fighting, soil and fruit fumigation, manufacturing and distribution losses. Due to the generally poor spatial resolution of available activity data for most processes covered by this analysis it was decided to build it around only four major regions: North America (USA and Canada), Western Europe (European Union (EU-15), Norway, Switzerland, Iceland), Japan and Rest of World (Latin America, Oceania, Africa, Asia (excl. Japan), the Commonwealth of Independent States and the Eastern European Countries in Transition).The regions used are the same as in most of the recent United Nations Environmental Programme (UNEP) Technical Options Reports. By using this small number of regions it avoided the need to create, use and report so-called "proxy data" for certain regions and countries (e.g. according to their share of gross domestic product of a larger region). Such proxies, generally have a significantly higher uncertainty than the original values from technology inventories for the four major regions. In the past North America, Europe and Japan together have been responsible for by far the largest share of emissions (>80%) of the halogenated compounds with large regions such as China, India or Africa contributing comparably little despite their large populations. The model has been designed to derive emission estimates for three years (base year, 2010 and 2020) covering a period of roughly 25 years. As the base year is close to the present, the year 1996 was selected for which data coverage by the UNEP Technical Options Reports is most complete for almost all processes in which ODS have been used in the past. In a few instances the years 1995 and 1997 had to be used as the base year in certain sectors due to the lack of data for 1996. The resulting error, however, is very minor compared to the overall uncertainties of emission estimates in this field.

1253 The reference scenario which is calculated for the years 2010 and 2020 is set up to make conservative assumptions about technological progress, i.e. it avoids reliance on large autonomous emission reductions without a corresponding regulatory framework. In regions in which companies, through their actions, already anticipate future regulation on greenhouse gas emissions, this might lead to an overestimate of future emissions. As a result e.g. in the case of Europe, derived reference scenarios from this study result in higher projected emission levels than analyses specifically dedicated to the European Union [5, 6]. The choice of present and future emission factors is based on a number of relevant studies [5, 6, 7, 8]. However, many simplifications had to be made for reasons of practicability and limited data availability. The projected evolution of emission factors in the future was based on expert judgement since internationally no accepted standards exist for this purpose. Resulting uncertainties are accordingly fairly large. Assumptions on the evolution of emission factors and the baseline penetration of improved technologies are the main sources of uncertainties. Underlying economic growth scenarios for different regions and applications are generally of lesser importance. With only a few notable exceptions, uncertainties of emission estimates and projections will generally be as high as +50% on a 95% confidence level. This value is limited to estimates of emissions in terms of mass flows of substance. The conversion into hypothetical 100-year carbon dioxide equivalents increases uncertainties significantly especially for the ODS. The reference scenario has been designed under the assumption of full compliance with the Montreal Protocol in all regions. This study was not designed to assess the costs of an accelerated phase-out of ODS in one or several regions. Therefore, the model permits an emission abatement exclusively for non-ODS comprising the Kyoto-gases: HFCs, PFCs and SF6. However, it is important to keep in mind that a number of interactions do exist between the transitions under the Montreal Protocol and potential emission reductions under the Kyoto Protocol. For the purpose of this study it was not attempted to economically capture such effects. Instead a natural turnover of capital was assumed. The main abatement options comprise improved containment, use of alternative fluids, use of not-in-kind technologies and process modifications in the case of point sources. Please refer to Harnisch and Hendriks [5] for details. While ODS emissions rapidly decline until 2020, the gases regulated under the Kyoto Protocol exhibit a fairly steep increase from 1996 to 2020. They are projected to double between 1996 and 2010 and then grow by slightly less than another 50% until 2020 (300, 600, 870 MT CO2 eq., respectively). Assuming a stabilisation of emission levels of the greenhouse gases in the Kyoto basket at 1995 levels, HFCs, PFCs and SF6 will globally contribute about 2 % of CO2 eq. emissions in 2010 and grow to 3 % in 2020 compared to about 0.9% in 1996. ASSESSMENT OF ABATEMENT AND C O N T R O L OPTIONS The emission reductions are calculated on an annual basis. All cost data of this report are calculated as 1999 US$. Abatement costs were calculated from the sum of annualised investment costs and annual operating and maintenance costs divided by mean annual emission savings. The annual operation and maintenance costs were assumed to remain fixed over the depreciation period. The annualised capital costs are calculated by multiplying the total investment with the annuity factor. Investment costs were annualised over their lifetime (here 15 years are used as default value) at a discount rate of 5% per annum which is a value commonly used in a macro-economic analyses. However, this is well below discount rates used for commercial investment decisions (10-30% per annum depending on the specific industrycorrespondingly resulting in higher specific abatement costs). The cost information used in this study is taken from a database created as part of the analysis "Economic Evaluation of Emission Reductions of HFCs, PFCs and SF6 in Europe" [5]. The study contains a detailed description of most technological abatement options used in this study for the IEA GHG. Notable exceptions are solvents and technical aerosols for which cost estimates from March [6] and MDI for which cost data from Enviros [9] were applied. Leakage and recovery in fire-fighting is assumed to exhibit a comparable cost structure to commercial refrigeration.

1254 Generally, it is assumed that economic and technological conditions across the globe will be comparable to the situation in the European Union. In the short term, this assumption will obviously be violated in many developing countries and in the economies in transition. In the longer run, it currently seems very appropriate to assume a continuation of the ongoing economic and technological convergence across the globe. To limit the complexity of this analysis, generally only one abatement option was assigned to each of the 22 sectors modelled. Based on the experience from the study for Europe often the least cost option among several candidates was selected. Alternatively, a weighted mean from a number of options was calculated to appropriately address different sub-sectors as was the case for the fairly diverse field of polyurethane foam production or for aluminium production. The selection of a technological option is not intended to be prescriptive. It is fully recognised that a dynamic process of research and development is currently reshaping many of the sectors studied. Frequently, new approaches nowadays marginalise what seemed to be a dominant technology. With a timeframe of 20 years ahead, many of the proposed abatement options can only be intended as "backstops" i.e. giving an indication that the final technical solution cost will exhibit equal or smaller costs than the proposed approach. TABLE 1 OVERVIEW OF EMISSIONREDUCTIONPOTENTIALSFOR HFCs, PFCs AND SF6 1996

2010

Cost range a

Total emissi ons b

Total emissi ons b

Reduction potential b

2020

Cost range a

Total emissi ons b

Reduction potentiaP

1 month, no pasture) 0.17 124 5 0.70 66 39 2.93 Pigs 0.45 101 10 3.05 60 39 7.06 The default IPCC values for MCF may be replaced by country-specific values which can include factors like (IPCC, 2001): timing of storage or application, length of storage, manure characteristics, determination of the amount manure left in the storage facility (as a methanogenic inoculum), temperature of indoor and outdoor storage or daily and seasonal temperature variation. In this paper, a dynamic model to determine the MCF is proposed that can include such factors. MATERIAL AND METHODS

Dynamic emission model A common system for manure management in the Netherlands is slurry storage in a pit below the animal confinements. Such slurry pit storage can be considered as an accumulation system with continuous filling. The methane emission in such a system depends on the filling time and the inoculum. The emission over time in accumulation systems has been measured in several experiments by Zeeman (1991). Based on these experiments, we assume for this paper, that the emission velocity (m3/day) in an accumulation system is linearly increasing with the filling time (Figure 1). We also assume 1 m 3 ~ 1000 kg slurry and 1 m 3 CH4 = 0.67 kg CH4. The emission velocity of cattle and pig slurry in an accumulation system at 15°C is: 1Tlcattle15of(t) = (12+0.47"t)'0.67"10 -3 and mpigs15oc(t) = (12+0.75"t)'0.67"10 3 (2) where m(t) is the emission velocity of methane in kg CH4 per m 3 slurry per day and t the filling time in days. This implies that the relation between emission and filling time is quadratic. The methane emission EF' as a function of time in kg CH4 per m 3 slurry can be found from: EF'(t) = ~__om(r)dr

(3)

1283 11CH4/t.d) 0.10-~

0----o

1

0.08~

~

-

2 nd f i l l i n g

period

3 rd filling

period

t, th filling period Sth filling period t,fh tilling period.mixed

0.06"

( I CHjI.d 0.15

)

=,-.--= 1'=t ftl|ing period o - - ~ 2 nd fillin 9 period

0.10

1

,e,

,~¢ "o, °,, .,,~,

7/'z/

,

.,\=

O.OL.

1 0.02

,

o

,

,

~o

,

,

8o

. . . . . lz0 16o

z~0 ' Ao time (doys)

0 ~,0

.

.- ..... ~

.. . . . . . . . . . . 80 120

160 firne (cloys)

Figure 1: A copy of figures 1a and 5 of chapter 5 of Zeeman (1991) for the emission velocity of methane in liters CH4 per liters manure per day for cattle (left) and pigs (right). These experimental results are for digestion of slurry in a continuous accumulation system at 15°C with 14% inoculation. The filling time was 100 days. The straight line is added to show the approximately linear relationship between velocity and time. According to Zeeman's experiments Eq. (2) and Eq. (3) yield for cattle slurry EF'cattle 15°c(t) = (12"t+0.23"t2)'0.67" 10.3

(4)

EF'pigs 15oc(t) = (12"t+0.37"t2)'0.67 •10.3

(5)

and for pig slurry

These equations are valid within the experimental range and conditions of Zeeman (1991), with filling times till 100 days.

Relationship between IPCC-model and dynamic methane emission model Both the IPCC model (1) and the dynamic emission model (4) for cattle and (5) for pigs, describe the methane emission of a slurry storage. The dynamic methane emission model can be compared with the IPCC model. Replace EF by EF', VS by VS' and substitute MCF(t) for ~Y'MCFjk .MS~jk in Eq. (1). jk

Equating this result with Eq. (4) gives for cattle slurry: MCFcattle 15°c(t) = (1.07"t + 0.0205"t2) •10.3

(6)

and with Eq. (5) gives for pig slurry: MCFpigs 15oc(t) = (0.44.t + 0.0137"t2) •10.3

(7)

To illustrate the consequences of Eq. (6) and Eq. (7) on the MCF, in Figure 2 the MCF is calculated for different filling times for cattle and pig slurry at a constant temperature of 15°C.

1284 100 ............

........ 6 0 - -

[cattle.]

.Z.../'! °''''''" .....o.]."" '

U 40

2O i

0 !---'- ~ 0 20

40

60

80

100

120

|

4 ....... l - - f 140 160 180

Time (days) Figure 2: MCF's (%) for slurry storages for pigs and cattle calculated using the dynamic model as a function of filling times in days at 15°C.

Temperature of slurry storage facilities in the Netherlands The emission depends on the storage temperature, Eq. (6) and (7) are valid at 15°C, there is no emission below 4°C. Due to climate control in pig housing, the average temperature of the indoor stored pig slurry is around 17°C (Novem, 1991) during the year. However, since the data of Zeeman is valid at 15°C, we assume for these illustrating calculations the pig slurry to be stored at 15°C. This may imply an underestimation of the MCF. The temperature of the slurry pit in cattle housing will be related to the outdoor temperature. The average temperature of a cattle slurry pit is assumed to be 15°C during June, July, August and September, and 10°C during the other months. The methane emission at 10°C is assumed to be half the emission at 15°C. With the latter, Eq. (6) is rewritten as: MCFcattle ~0oc(t) - (0.53.t + 0.0102.t2) •10-3 (8)

RESULTS The dynamic model describes the relation between methane emissions and filling time for slurry storage. As an illustration the emission factors of a common cattle and pig farm will be calculated. Due to covering and the low temperature of the outdoor slurry storage the emission of methane is considered to be negligible low, compared to the emission from the slurry pit. It is assumed that at least 10% of the slurry will remain in the pit (as inoculum) because it is practical impossible to empty the pit completely. To calculate the methane emission on a yearly basis the MCF will be calculated using the dynamic model for each storage period, starting with the remaining of the last period until the pit is emptied. In Table 2 the resulting MCF and emission factor EF'3 are given. For pig farms all manure is stored in the slurry pit (typical capacity 400 m 3) of the pig housing. When the pit is full, manure is pumped to the outdoor silo. In case of manure application, manure is taken first from the pit, and from the silo if the pit is empty. Most manure will be transported to other farms and the rest will be applied on the farm in March and in August (2x50% of the stored manure). Here, Eq. (7) will be applied.

1285 The manure application times for cattle farms are observed average values for 2 years at 12 farms, which include grazing during May till October. In case of grazing, 50% of the manure is assumed to be dropped on pasture. The average manure application, expressed as a percentage of the manure stored in the pit, is 10% in February, 20% in March, 15% in April, 20% May, 15% in June, 10% in July and 10% in August (application is prohibited during the other months). Eq. (8) will be applied for the period October till May and Eq. (6) during the other months. TABLE 2 The methane conversion factor MCF (%) with resulting emission factor EF'I (kg CH4/m 3 slurry), calculated for pigs and cattle according to the static IPCC model of Eq. (1) compared with the MCF and EF'3 calculated using the dynamic models of Eq. (6), (7) and (8). Bo is the biodegradability in m 3 CH4/kg VS. VS' are the volatile solids in kg per m3 slurry. using static model (IPCC) using dynamic model: Eq. (6), (7) and (8) Livestock population I3o VS' MCF EF'l VS' MCF EF'3 Cattle (> 1 month, pasture) 0.17 124 5 0.70 66 21.5 1.61 Pigs 0.45 101 10 3.05 60 46.2 3.86

CONCLUSIONS Emissions of methane from agricultural sources are normally calculated in accordance to the IPCC good practice guidelines. A new dynamic model has been proposed to derive values for the MCF which include dynamic factors like slurry storage time, loading and unloading rates and temperature. Research from Zeeman (1991) suggests that the emission velocity is linearly increasing with filling time, i.e. the relation between emission and filling time is quadratic. As an illustration the model is used to derive values for the methane conversion factor MCF and the resulting emission factor, depending on filling time and temperature. The model has been applied to a typical pig and cattle farm. The results show that the procedure to determine the MCF can have a great influence on the emission factor. The proposed procedure can be used to improve calculations of national emissions and to define policies to reduce methane emissions from manure storage.

REFERENCES 1. IPCC, 1996. Revised 1996 IPCC guidelines for national greenhouse gas inventories: Reference manual. 2. IPCC, 2001. Good practice guidance and uncertainty management in national greenhouse gas inventories. 3. Novem, 1991. Commersialisering van koude vergisting van varkensdrijfmest onder stal met behulp van kapjessysteem, Novem/RIVM, Sittard/Bilthoven The Netherlands, no 9134, 50 p. 4. Van Amstel, A.R., R.J. Swart, M.S. Krol, J.P. Beck, A.F. Bouwman & K.W. van der Hoek, 1993. Methane. The other greenhouse gas. Research and policy in the Netherlands. Report no: 481507001, RIVM. 5. Van Dijk, W., 1999. Adviesbasis voor de bemesting van akkerbouwen vollegrondsgroentegewassen. PAV, Publicatie nr. 95, maart 1999. 6. Zeeman, G., 1991. Mesophilic and psychrophilic digestion of liquid manure. Thesis Agricultural University Wageningen.

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Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1287

COAL MINE V E N T I L A T I O N AIR M E T H A N E C A T A L Y T I C C O M B U S T I O N GAS TURBINE S. Su, A. C. Beath and C. W. Mallett CSIRO Exploration and Mining, Technology Court, Pullenvale, QLD 4069, Australia

ABSTRACT

This paper describes the development of a catalytic combustion gas turbine system that can use and mitigate methane in coalmine ventilation air. Each year underground coalmines throughout the world emit methane that is equivalent to over 200 million metric tons of CO2 in terms of the global warming potential from their ventilation systems. Although the concentration of methane contained in these ventilation air flows is quite low (typically less than 1 percent), the volume of ventilation air is so large that ventilation systems constitute the single largest greenhouse gas source from underground coal mines. The coalmine ventilation air methane catalytic combustion gas turbine technology being developed can be used to mitigate greenhouse effects of the ventilation air by catalytic oxidation and to generate electricity. This gas turbine system is simple and reliable compared to other systems. Bench-scale ventilation air methane catalytic combustion tests were used to obtain the design parameters of a pilot-scale demonstration plant. Four catalysts were tested at different temperature, pressure and CH4 concentrations. The experimental results are presented in this paper along with the brief description of methane catalytic combustion basics and the conceptual design of the ventilation air methane catalytic combustion gas turbine system.

INTRODUCTION

Methane (CH4) is the second largest contributor to global warming among anthropogenic gases, after carbon dioxide (CO2). It is estimated to be 21 times more effective at trapping heat in the atmosphere than CO2 over a 100-year period [ 1]. A major source of methane emissions is underground coalmines, estimated to produce approximately 10% of anthropogenic methane emissions worldwide [2]. This corresponds to a worldwide annual production of methane equivalent to over 200 million metric tons of CO2, in terms of CH4 global warming potential [ 1], from coalmine ventilation systems. Although the concentration of methane contained in these ventilation air flows is quite low (typically less than 1 percent), the volume of air that the systems move into, through, and out of the mine is so large that ventilation systems constitute the single largest source of methane release to the atmosphere from underground coal mines [3]. A typical gassy mine in Australia produces ventilation air at a rate of approximately 150 to 300 cubic meters per second [4]. This results in the Australian coal mining industry contributing approximately 6.5% of Australia's greenhouse gas production while producing only 1.9% of GDP (1995/1996) [4]. Of these greenhouse gas emissions from coal mining, 72% are in form of fugitive emissions of methane from underground mining. Typically, at a gassy mine methane is contained in the following three streams: (1) mine ventilation air, (2) gas drained from the seam before mining, and (3) gas drained from worked areas of the mine e.g. goafs. In Australia, approximately 64% of the methane emitted is contained in mine ventilation

1288 air at a concentration between 0-1%, and the remainder is in the combined drainage gas streams, typically at concentrations greater than 50% methane by volume. Ventilation air methane is difficult to use as an energy source as the air volume is large and the methane resource is dilute and variable in concentration. Several technologies have been or are being developed to dispose of the methane in mine ventilation air and potentially recover useful energy. Carothers et al. [2] reviewed most of ventilation air methane utilisation technologies in terms of technical and economic feasibilities. Generally, utilisation technologies of methane in ventilation air divide into two basic categories: (1) Ancillary uses involve substituting the ventilation air for ambient air in combustion processes. This has the advantage that methane in the ventilation air acts as a supplementary fuel in the combustion process. Suitable combustion processes include gas turbines, internal combustion engines and coal-fired power stations; (2) Principal uses involve combustion of the methane in ventilation air as a primary fuel without reliance on another source of combustion. For example, thermal flow-reversal reactors (TFRR) can sustain operation by maintaining the core temperature just above the auto-ignition temperature of methane and can operate with a methane concentration as low as 0.3%. Catalytic versions of these systems, known as catalytic flow-reversal reactors (CFRR), can operate with methane concentration as low as 0.1 percent. The TFRR and CFRR can cope with variability of methane in ventilation air due to the thermal inertia of the systems. The main limitation of the systems is that it is difficult to extract useful energy, so they generally provide only mitigation by preventing release of the methane. Heat can be recovered from the systems, but variations in methane concentration are likely to cause instability in the system, as it is difficult to maintain the working fluid that recovers the heat at a constant temperature and flow rate. The ventilation air methane catalytic combustion gas turbine technology that CSIRO is developing can be used to mitigate methane from the ventilation air by catalytic oxidation and to generate electricity. This gas turbine system is simple and reliable compared to other systems in terms of operation and recovering heat. Bench-scale ventilation air methane catalytic combustion tests were used to obtain the design parameters of a pilot-scale demonstration plant. Four catalysts were tested at different temperature, pressure and CH4 concentrations. This paper presents the CH4 catalytic combustion experimental results along with a brief description of CH4 catalytic combustion basics and a conceptual design of the ventilation air methane catalytic combustion gas turbine system.

METHANE CATALYTIC COMBUSTION Mechanism and Kinetics

The combustion mechanism of methane can be represented in a simple form with Eqn. 1, however, this is a gross simplification since the true reaction mechanism involves many free radical chain reactions [5].

CH4 + 202 = CO2 + 2H20

/~-I(298 ) =

-802.7 kJ/mol

(1)

Studies of the kinetic mechanisms of methane catalytic combustion can become quite involved when multistep surface reactions are considered. Chou et al. [6] used 23 different reactions in their numerical study of methane catalytic combustion in a monolith honeycomb reactor. The situation becomes even more complicated when considering heterogeneous reactions and the use of surfaces as reaction sites. Figure 1 shows a possible mechanism for methane catalytic oxidation proposed b y O h et al. [7]. Methane catalytic combustion is a multi-step process involving diffusion of methane and oxygen to the catalyst surface, adsorption onto the catalyst, reaction, and then desorption of the product species from the surface and diffusion back into the bulk [8]. Most kinetic investigations have been performed under conditions where oxygen is present in excess of the stoichiometric ratio. Resulting from this has been the finding that the reaction is independent of the oxygen concentration. The reaction order with respect to methane is generally found to be between 0.5 and 1 [5]. No definitive agreement has been reached on the kinetic mechanism of methane catalytic oxidation.

1289 CH4(g)

HCHO(g)

;T-H CH4(a)

CO(g)

H2(g)

CH3.(a)+O ~T decomp. ~T ~T ~ or ~ HCHO(a) • CO(a)+2H(a) CH2"(a) direct oxidation

+O

CO2(g)+H20(g)

Figure 1: A possible mechanism for methane catalytic oxidation [7] (a) adsorbed and (g) gas phase R e a c t o r Types

A number of different reactor types have been used for catalytic combustion. Generally, these can be classified into three types of reactors: honeycomb monolith, packed bed, and fluidised bed. Characteristics of the different types make them suitable for different types of processes. For example, the CFRR process uses packed bed reactors [2], as these have a high thermal inertia that suits the process. However, the honeycomb monolithic type reactor has better characteristics for power generation applications due to its very low pressure drop at elevated mass throughputs, high geometrical area, and high mechanical strength [9]. Monoliths consist of a structure of parallel channels with walls coated by a porous support with catalytically active particles, as shown in Figure 2. The monolith structure is normally ceramic, but may also be metallic, and acts as a substrate for a washcoat slurry of base metals (such as alumina) on which catalytic material (typically noble metals such as palladium or platinum) are placed [8].

Ceramic Monolith

~

vidual nel Cross

Section

Channel

8llb~ CH4+Ai~

SupportedCatalyst Laser

~uudCe~,

Pallmllm or

Rhmltwm

Figure 2: Illustration of a monolith reactor [8, 10] EXPERIMENTAL RIG AND CATALYSTS An experimental rig was constructed to test coalmine methane catalytic combustion performance by using different catalysts at different operating conditions, as shown in Figure 3. The experimental rig consists of two air heaters, a mixer, a catalytic combustion chamber, a cooler, fuel supplier, power supply, and sampling system. The mixer is used to dilute concentrated methane (99.99%) into air to produce a dispersed low concentration methane and air mixture that simulates coalmine ventilation air. Two water-cooling probes are used in the gas sampling system, and installed before and after the combustor respectively, are used to quench reactions at the sampling points. Two dryers are used to dry the sampling gases taken by the probes to ensure that no water vapour goes into a gas chromatography (GC). The GC determines CO, CO2, CH4, 02 and N2 of the dried gas stream. Ledwich et al. [11] and Lee et al. [5] carried out the surveys on methane catalytic combustion and determined that platinum and palladium are generally found to be the most active catalysts for low temperature oxidation. Therefore, four different honeycomb monolith catalysts, each consisting of a ceramic support with washcoats containing different concentrations of Pd and Pt, were selected for this study. Table 1 summarises the properties of the four catalysts. Catalysts 1 to 3 have an acceptable maximum catalyst bed

1290 temperature for short periods of 850-920°C, while catalyst 4 has a higher peak operating temperature of 1050°C.

Figure 3: Ventilation air methane catalytic combustion experimental rig

TABLE 1 BASIC PROPERTIESOF THE CATALYSTS Number

No. 1 No.2 No.3 No.4

Catalyst/ Substrate

Cell density, cells/cm2

Pd/A1203 Pt/AI203 Pt/AI203 Pd/A1203

62 62 62 62

Surface area, Loading, Precious metal, g/monolith m2/cm3 g/m3 Pt Pd Rh SubWashstrate coat 0 0.9217 0.1843 0.0155 30.5 649.4 0.0155 30.5 1765.7 2.6515 0 0.5303 1.4463 0 0.1446 0.0155 30.5 882.9 0 2.0534 0.4107 0.0155 30.5 1765.7

Max

continuous catalyst bed temp., °C 750 750 750 950

The experimental procedure was to preheat the catalyst to the test temperature using heated air before introducing methane into the air to produce the desired concentration. Changes in the temperature of the air leaving the catalytic reactor with time were used as an indication of catalyst performance. The variation in gas composition from inlet to outlet of the catalytic reactor were used to determine the efficiency of the catalytic process according to Eqn. 2, where, r/cH, is the CH4 conversion rate as a percentage, (CHn)in,m is the measured CH4 concentration in the reactant stream and (CHa)out,m is the measured CH4 concentration in the product stream. (cn4) . . . . x ( 5 0 - ( f n 4 ) i n m ) ) x

lO 0

(2)

E X P E R I M E N T A L RESULTS Catalyst tests were conducted at different preheated air temperature, pressure, space velocity and CH4 concentrations to determine the operational parameters at which CH4 can be fully oxidised into CO2 and H20 for each of the catalysts. Figure 4 shows some typical experimental results on CH4 catalytic combustion performance. Related operating parameters are shown for each run individually in the figure. As a general observation, higher operating pressures typically result in higher conversion of methane. This is due to that the combustion intensity is higher and the relative heat loss from the reactor is lower when the operating pressure is higher and the space velocity is kept constant. The results shown in Figures 4b and 4c

1291 can identify this effect for catalyst 1, as at 6.2atm almost total combustion of methane can be achieved for a methane concentration of 0.3325% while at 1.3atm a methane concentration of 0.601% is required for the catalyst to achieve near complete combustion. Figure 4c shows the results for an extended test where the temperature of the air entering the catalytic reactor was varied during operation. This shows that, for catalyst 1 and an operating pressure of 1.3atm, it is difficult to maintain combustion when the inlet temperature is less than 475°C, even with the relatively high methane concentration of approximately 1.07% and a catalyst temperature in excess of 600°C at the time the inlet temperature was changed. However, combustion can be initiated with a concentration of only 0.6% with an inlet gas temperature of 525°C.

7007 °li.......... / !

750 ~ 700 ! Stop CHim/~c~ion Test on 04/09/01 Catalyst 1, ff 650 at 6.2atm 600 !~_ ~ ~ ...... Inlet ,.~ 550 . . . . . Outlet 500 . . . . . 450 ~ S t a ~ n~0.3325% 0.03% 400 4 injectio C _ . ~ ~ 4

~Ii 650 / // Catalyst I, /_~L at6.2alm 600 ] St~p CH4 injection ] , I [ - - - Inlet 550 [ ~ ~1 .......... Outlet 500 ] ~S~-~CH--ml-ecilon 0.7085~ 0000% 450 4 t-I I CH4 o ~H 4 o 400 o ~ g g ........ oo oo tr~ o¢ ~ .--., CAT- 100102-N6 ,., ~.., 6< ,.. ~,., Time

........ Ai ....,

Ai ,.. Ai ,... Tim~

~..,

(a) 750

(b)

__/ ...... I /" ,i N I I//" N I1~[ N2 " // Increase CH4 ----- ~ // / concedatration ~------a_

700 650 600

~ 550 500

j'-Stop'~H4 injection I "., . / I N - vi " " "~ I Extinguished[t I due to lower inlet I temperature '

/ Start CH4 injecti ..... Reduce inlet te'~'mperature - I/-'''~

450 400

CAT-040901 -E4

.

~ g . ~S ~;

~ ~

g ~.

,..

,.,

,.,

,.,

,.,

~ ~;

~ ~ . ~ ~5

~ ~ g ~5 ~5 ~

~ ~

~ ~

Test on 10/01/02 Catalyst 1, at 1.3atm Inlet Outlet

CH4 N l: 0.601% Nlb: 1.071% N2: 1.071% N3: 1.063%

Time

CH4 NI 0.034°A Nlb: 0.000% N2: 0.000% N3: 1.510%

CAT- 100102-N 1-3

(c) 750 700

Stop CH4/.._inj~n .....

~650

TeStcatalystOn 01/10/012,

at 4.46arm

I~-,~600550

/

Inlet

~ 500

Outlet

~450 ~ tio~n 0.867% 0.0025% 400 Start CH 4 injec C ~ ............ ,~ ,~ ,~ ,~ ,~ t-- CAT-011001-I5 Time

(d)

900 [ . 800 700

r """. . . . . . -¢"~i Test on 30/01/02 Catalyst 4, St lap CH 4 injection at 6.2atm i i ~ Inlet Slart CH 4 injectk~n Outlet

t

z l

6°°1i/

I~'~ 500

400~

~. . . ~. . . ~. . ,eq m Ai ~,., Ai .., _., Time

CH 4

000% CH 4

~ >

~ * CH 4 at the inlet ,n- is estimated by Ai ,_, calculation CAT-300102-P2

(e)

Figure 4: Performances of CH4 catalytic combustion From analysis of the experimental results it has been possible to establish guidelines as to the minimum gas concentration and temperatures at which each of the catalysts will function adequately. The catalysts with higher loadings of precious metals typically perform better than those with lower loadings, in particular by functioning at lower temperature. It was also determined that the palladium-based catalysts functioned over a greater range of conditions than those containing platinum, as also concluded by Ledwich et al. [ 11 ] and Lee et al. [5]. Catalyst 4 is the preferred option due to its higher operating temperature and high catalyst

1292 loading, that allows for a greater range of operating conditions. For example, to achieve a methane conversion rate of over 90%, the air containing methane needs to be preheated to just over 450°C at 6.2atm, depending on methane concentration. When using this catalyst, it should be possible to maintain near complete combustion of methane for streams containing concentrations of methane greater than 0.6% as long as the temperature ofthe streams is above 500°C and the pressure over 1.3atm.

D E M O N S T R A T I O N SYSTEM DESIGN

Methane is contained in the ventilation air from gassy coalmines at all times, however concentrations and flow rates vary. The use of this air for combustion dilution and cooling of the turbine inlet scroll and first stage in normal industrial gas turbines will result in a significant fraction of the methane passing through the turbine without combusting. This results in a more complex turbine system that requires compressed air from other sources, as well as compressed ventilation air, if all methane is to be combusted. The demonstration system design is therefore constrained by several criteria such as performance of the catalyst to minimise methane emissions. From these criteria, potential arrangements of gas turbine systems were proposed and analysis was performed using a commercial process analysis package (HYSYS) to select and optimise a system design. This analysis determined that it was possible to arrange a system that could not only efficiently combust methane streams with concentration of approximately 1%, but also produce a net electrical output. A conceptual design of the system has been completed and the major operating parameters finalised, however, final design details and operating parameters are subject to modification in consultation with the turbine designer and manufacturer.

ACKNOWLEDGEMENTS

The authors wish to acknowledge the ACARP funding for this project. We would like to thank Mr Dominic Foran from Delphi Automotive Systems, Mr Jeff Condren, Mr Patrick Glynn, Mr Ian Hutchinson and Dr David Harris from CSIRO for their help in a construction and operation of the experimental rig.

REFERENCES

.

10.

11.

USA EPA (2001). Non-C02 Greenhouse Gas Emissions from Developed Countries: 1990-2010. U. S. Environmental Protection Agency, Office of Air and Radiation, Sept. 2001. Carothers, P., and Deo, M. (2000). Technical and Economic Assessment: Mitigation of Methane Emissions from Coal Mine Ventilation Air. Coalbed Methane Outreach Program, Climate Protection Division, U. S. Environmental Protection Agency, EPA-430-R-001, February 2000. http ://www.epa.gov/coalbed/vam/index.htm. Wendt, M. N., and Mallett, C. et al. (2000). Methane Capture and Utilisation, final report. ACARP Project C8058. CSIRO Exploration and Mining, Brisbane, May 2000. Lee, J. H., and Trimm, D. L. (1995). Fuel Processing Technology 42, 339. Chou, C. P., and Chen, J. Y., Evans, G. H., and Winters, W. S. (2000). Combustion Science and Technology 150, 27. Oh, S. H., Mitchell, P. J. and Siewert, R. M. (1991). In: Catalytic Control of Air Pollution: Mobile and Stationary Sources, pp. 12-25, Silver, J. E. (Eds). 202 nd National Meeting of the American Chemical Society, 25-30 August 1991, ACS Series, Vol. 495. Foran, D. (2001). Personal Communication: Catalytic Converter- Production Specifications. Delphi Automotive Systems, Australia. Cimino, S., Pirone, R., and Russo, G. (2001). Industrial Chemical Research 40, 80. Geus, J. W., and van Giez-en, J. C. (1999). Catalysis Today 47, 169. Ledwich, J., and Su, S. (2001). Catalytic Combustion of Coal Mine Ventilation Air: Literature Review and Experimental Preparation. CSIRO Exploration and Mining, May 2001, Australia.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1293

THE E F F E C T I V E M A N A G E M E N T OF M E T H A N E EMISSIONS FROM N A T U R A L GAS PIPELINES S. Venugopal Department of Community, Safety and Environment TransCanada PipeLines Ltd. Calgary, Alberta, T2P 5H1, Canada

ABSTRACT Methane emissions from TransCanada can be categorized into fugitive losses and vented emissions. There are a number of facets to TransCanada's methane emissions management program: source identification, quantification, tracking system, mitigative actions, pilot program, full scale implementation, monitoring progress, and continuous through research and development. In 2001, TransCanada's methane emissions management program avoided 1.3 millions tonnes of carbon dioxide equivalent from being emitted to the atmosphere. This paper documents TransCanada's methane emissions management strategy and its implementation from source identification to research and development.

INTRODUCTION TransCanada PipeLines Ltd. (TransCanada) is Canada's largest natural gas pipeline company. TransCanada owns and operates a 37000 kilometer pipeline system that contains more than 110 gas compression facilities, 1200 gas metering facilities and over 5000 valve sites. The gas compression facilities have a combined capacity of nearly 4000 megawatts. TransCanada's Canadian facilities emit nearly 8 million tonnes of carbon dioxide equivalent. Based on 2001 data, approximately 13 per cent of TransCanada's greenhouse gas emissions originate from methane losses along its pipeline network. Without the methane emissions management program in place TransCanada's greenhouse gas emissions would be 16 per cent higher (equal to 29 per cent of total greenhouse gas emissions). Carbon dioxide (84 per cent) and nitrous oxide (1 per cent), result from combustion processes that take place at the compression facilities contribute to the remaining of 85 per cent of greenhouse gas emissions.

A METHANE EMISSIONS MANAGEMENT MODEL The management of methane emissions at TransCanada is part of TransCanada's overall strategy towards Climate Change. The Climate Change strategy is guided by several principles developed by TransCanada, of which one principle is dedicated towards the development and implementation of a greenhouse gas emissions reduction program. The methane emissions management model (Figure 1) at TransCanada can be broken down into three tiers: i) Tier 1 -

1294 Senior Leadership Support, ii) Tier 2 - Program Management, and iii) Tier 3 - Execution and Monitoring. This model is based on TransCanada's experience in the development and implementation of a methane emissions management program. It was developed in order to assist and maintain future methane emissions management programs on natural gas pipeline system. I Tier

1 - Senior

Leadership Support

provide resources approve management p l a n

-

Tier 2

-

I

w i t h business needs performance management

- alignment -

Program Management

]

l

Development - source identification - quantification - tracking system - mitigative actions

-

I

1

pilot program

- trouble shooting

- metric

- annual

- s e t t i n g targets - measuring progress

- communtca

I n

Tier 3

I

i ~i,o,~ro~.~ I

1

roliout

-

Execution and Monitoring

t

I~o,, s.,o,m~, .... ,a,,oo I

I

I Continuous Improvement - research and development

I , i

I

i

I ~°ni'°r~n~ I

Figure 1: A Three Tier model for methane emissions management from natural gas pipeline. Tier 1 provides the necessary leadership and resources needed to carry out the management program. There are two key elements to Tier 1, sponsorship and accountability. One senior level leader within the firm is assigned the role of championing the program. This champions role is to obtain support from leaders of the various departments that influence decision making with respect to methane emissions and control strategies. The other key role for this champion is to provide accountability for the program. That is, making sure that the program is aligned with business needs and that it becomes a measure of business performance. This alignment demonstrates to all parties that management of methane emissions is an important part of the business cycle. Tier 2 and Tier 3 are carried out by a multi stakeholder team from the various interested departments across the firm. There are several components within Tier 2; development of an emissions management program is the first step and it involves identification of emissions sources, quantification of emissions, development of a system to track emissions and take mitigative actions. The identification emissions sources leads to the development of techniques for emissions quantification. In some cases, quantification means the use of standard engineering calculations to quantify emissions. While in other cases, it may involve research and development work to develop procedures and protocols to quantify emissions. In order to control and effectively manage methane emissions mitigative actions need to be investigated and implemented. The next step in the management plan is it's "Implementation." There are two components to this stage, development of a pilot program and a communication plan. The pilot program should be a focused effort that attempts to address possible issues that will arise in the full scale implementation of the management program. Some considerations for the pilot program are, geographical area, audience, sites for field testing the quantification and tracking systems, and evaluating mitigation options. This communication needs to be focused on all levels of management and employees involved with the program. The management program will require ongoing "Maintenance." This maintenance needs to be carried out with a mechanism for trouble shooting during the annual roll out of the program. The annual roll out is an opportunity for communicating messages and addressing issues that arise in

1295 the previous year. Performance measurement is an important component in the overall management plan. The first step is to determine a metric for the performance, the next is establishing both short term and long term targets and then establishing a periodical system of measuring progress. Continuous improvement is a business value as well as an environmental ideal. Research and development is an important tool for achieving this ideal. Special effort needs to be put forth so that new and innovative ideas for emissions quantification, mitigation and management are continually sought after. The final stage of the model, Tier 3, is Execution and Monitoring. There are three components to be considered at this point: implementing a pilot program, full scale implementation and ongoing monitoring. The pilot program phase is really the opportunity to assess the program and its effectiveness on a small scale. A comprehensive pilot program is needed before full scale system implementation. Another important element is monitoring, where a process is put in place to asses the program on continuous basis.

THE TRANSCANADA EXPERIENCE Methane is emitted to atmosphere during the construction and operation of gas metering stations, gas compressor stations, valve sites and from the pipeline itself. There are two categories of methane emissions arising from TransCanada's operations; fugitive losses and vented emissions. Fugitive losses are either engineered emissions of methane or leakages that occur on equipment such as valves and flanges. Vented emissions of methane arise from the evacuation of natural gas (which is mainly composed of methane) from pipelines, losses from compressor starts to purging of pipelines. The methane emissions management effort is facilitated by the Department of Community, Safety and Environment. However, it is not a completely integrated system of methane emissions management. This is shown in Figure 2. Fugitive losses from TransCanada's pipeline network are managed by a multi stakeholder team, known as the Fugitive Emissions Management team (FEMT) and the vented emissions are managed by the Blowdown Emissions Committee. I

I

Methane Emissions Management

- facilitated by Community, Safety & Environment I

I Meter Stations + Compressor Stations + Valve Sites + Pipeline ] - assets that contributeto methane emissions

I

.... - Fugitive Emissions Management Team

/

I

I

1

,

- Engineered Emissions I Equipment Leakage I Pipeline Leakage

I I ve.

I

- Blowdown Emissions Committee

1

/ - Venting fi'om Pipelines I Compressor Starts Purging of Pipelines

I

Figure 2: The methane emissions management structure at TransCanada is divided into managing fugitive losses and vented emissions.

Management of Fugitive Losses The FEMT is comprised of management and personnel from engineering, representatives maintenance regions across TransCanada and the environment department. The team is sponsored by a senior management representative. There are three major areas of program development and management for the FEMT. This is shown in Figure 3.

1296 ~

FugitiveEmissionsManagement Team - all aspectsof Tier I, Tier 2 and Tier 3

Research and Development

Leak Detection and Repair - aligned with maintenance program

- engineeredemissions - biofiltration - re-injectiontechnology

- aerial surveyof system - systemto track LDARand emissions savings

Figure 3: The fugitive emissions management team has three major areas of management responsibilities, research and development, fugitive emissions measurement and implementing a leak detection and repair program. The key element behind the measurement program is the device High Flow Sampler, which was developed through collaborative research with government and industry groups. This technology has allowed TransCanada to accurately measure fugitive losses. Approximately 20 per cent of the facilities are subjected to High Flow Sampler measurements annually. The data collected from these measurements are used to develop emission factors for TransCanada facilities and are used to report emissions internally within TransCanada and externally. It also provides the basis for setting annual targets for fugitive emissions reductions. In parallel with the measurement program, is the Leak Detection and Repair (LDAR) program. This program is closely aligned with TransCanada's preventive maintenance program and is administered through this process. The LDAR program is an annual activity for selected facilities across Canada. A system has been implemented using the FEMT to track the LDAR progress and resultant savings in emissions from mitigation activity. There are two research initiatives underway to address engineered emissions. One is a biofiltration project, where methane is oxidized in a biofilter cell into carbon dioxide. This reduces global warming impacts by 85 per cent. The other major initiative is research into the reinjection of engineered emissions into the pipeline system. In 2001, approximately 487 kilo tonnes of carbon dioxide equivalent of fugitive losses were avoided from being emitted to the atmosphere.

Management of Vented Methane The management of vented methane is a shared responsibility between the engineering and operations departing. The Blowdown Emissions Committee monitors and facilitates the management of the vented emissions. This committee is sponsored by a senior management representative and a variety of stakeholders are represented on this committee. Tier 1 and Tier 2 levels of the methane management models are monitored by this committee (Figure 4).

1297

- monitors only Tier I and T i ~ 2

O u t a g e Declslom Model - decision making tool - integrated with societal

~

~

,

~

- field input through forms - as ,'lccountin - g:onthly r = g r t s

- transfer compression - air powered expellers - risk planning options - pipeline inspection tools - butlcnng and hot tapping - StOl~.le plugs - repair sleeves

Figure 4: Venting of methane emissions to atmosphere is monitored by the Blowdown Emissions Committee. A tool called the Outage Decision Model (ODM) is the crucial element in minimizing vented methane emissions. This tool has been developed by TransCanada's operations planning group to facilitate how pipeline and system outages are addressed. Construction and maintenance activity along the pipeline facilities often require the system to come off line. In the past, this has been synonymous with the venting of methane. Outages along the system also have a financial impact to TransCanada in the form of the value of natural gas that is vented and lost revenue during the outage time. Tracking of methane fall into two categories, actual emissions emitted to atmosphere and the emissions saved by implementing mitigative measures. The volume of methane emissions saved is captured by the emissions tracking system that is managed by the operations planning group. The methane vented is captured in TransCanada gas accounting system. When an outage is required, a request in put forth to the operations planning group. The ODM is used to determine the best course of action for the outage, which includes mitigation techniques that are employed to reduce the venting of methane. During the outage itself, field personnel are required to fill out forms that provide detailed operations information that allow the gas accounting system and the emissions tracking system to determine the volume of methane vented and saved. There are a number of mitigative actions that TransCanada uses to reduce the volume of methane emitted to atmosphere. Many of these have been a result of research and development projects. Some of the mitigative actions are summarized below: i) Transfer Compression - When a section of pipe is isolated or shut down for maintenance, one or more transfer compressors are used to pump natural gas from the isolated section of line into another section that is still in operation. In 2000, 635 kilo tonnes of carbon dioxide equivalent were avoided from being vented to atmosphere. ii) Inline Inspection - TransCanada is now testing a pipeline inspection tool, known as a pig, that uses electro-magnetic acoustic transducers to reliably detect stress corrosion cracking (SCC.) If successful, this technology would further reduce the need for venting methane. Detection of SCC in a gas pipeline has previously required the use of ultrasound and has resulted in the venting of methane. iii) Buttering and Hot Tapping - Buttering and hot tapping procedures allow a new section of pipe to be welded to an operating pipeline without the need for natural gas flow to be shut off or vented to the atmosphere. In 2001, 160 kilo tonnes of carbon dioxide equivalent was avoided from being emitted to atmosphere.

1298 iv) Stopple Plugs - Large, portable pipeline plugs are called "stopples." These are used to isolate a short length of pipe and avoid large volumes of methane from being emitted to atmosphere. Emissions savings of 13 kilo tonnes of carbon dioxide equivalent resulted in 2001. v) Repair Sleeves - Fibre or steel reinforcement sleeves are used to permanently repair corrosion in pipeline sections without shutting down service or venting methane to the atmosphere. Emissions savings of 64 kilo tonnes of carbon dioxide equivalent resulted in 2001.

CONCLUSIONS There are a number of facets to TransCanada's methane emissions management program: source identification, quantification, tracking system, mitigative actions, pilot program, full scale implementation, monitoring progress, and continuous through research and development. The management of methane emissions is coordinated through a multi stakeholder team that consists of personnel from engineering, field operations, environmental protection and system operations. REFERENCES 1. Howard, T., Lott, R.A., and Webb, M. (1995). New Techniques Developed for Measuring Fugitive Emissions. Pipeline and Gas Industry. pp. 33-38.. 2. McBrien, R., Jones, B. and Venugopal, S. (1997). Effective Management of Fugitive Emissions from Natural Gas Transmission Facilities, Proceedings of the Air & Waste Management Association Speciality Conference - Emerging Air Issues for the 21 st Century: The Need for Multidisciplinary Management. Calgary, Alberta. September 22-24.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1299

NITROUS OXIDE EMISSION FROM PURIFICATION OF LIQUID PORTION OF SWINE WASTEWATER Takashi Osada

Dept. of Livestock Industry Environment National Institute of Livestock and Grassland Science, National Agricultural Research Organization, Japan 2 Ikenodai, Kukizaki, Ibaraki 305-0901, JAPAN

ABSTRACT

N20 is an essential greenhouse gas involved in world climate changes [ 1]. A large amount of nitrogen in livestock wastewater is treated with an activated sludge system to prevent public water pollution. In Japan, about 3% of CH4 and about 17% of N20 anthropogenic generation sources are presumed to be of livestock excrement origin [2], and its curtailment is necessary. To reduce N20 emissions from fill-and-draw type activated sludge units treating swine wastewater, N20 emissions were compared between the continuous aeration process (conventional process) and the intermittent aeration process. About 5% of the influent nitrogen was emitted as N20 gas using the conventional process under 0.5 kg m -3 d -I BOD loading and a temperature of 20°C. Most of the N20 was emitted during the first hours of aeration, beginning just after daily charging. Less than 0.05% of the influent nitrogen was emitted as N20 gas during the intermittent aeration process under two temperatures used (5°C and 20°C). The total emission of other harmful gases (NH3 and CH4) was negligible.

INTRODUCTION

Suitable processing and adequate usage of livestock excrement are serious on-going issues that affect livestock farming [3]. In areas where the livestock density per unit area is especially high, for example, parts of Europe and Japan, this is a serious problem. In Japan, the annual nitrogen amount (753Gt) contained in livestock waste was nearly equal to the annual consumption of nitrogen (600Gt) on cropland where chemical fertilizer had been spread (Table 1, [4]). This means that a large part of the nitrogen currently available in Japan is superfluous; it is difficult to apply and use all the livestock wastes on cropland. Surplus animal waste, especially wastewater handling, also poses a problem and must be carefully treated to protect public water [5]. To prevent surface and underground water pollution, a large amount of the nitrogen in livestock wastewater is purified with an activated sludge system. The activated sludge process with an intermittent aeration process (IAP) is reportedly effective for swine wastewater [6]. High removal efficiencies for biochemical oxygen demand (BOD), total organic carbon (TOC), total nitrogen (TN) and total phosphorus (TP) were achieved with the lAP. But, no attention has been paid to the fate of nitrogen gasses lost by this treatment system. In recent research, livestock manure has been suspected of contributing significantly to the emission of methane (CH4) and nitrous oxide (N20), both important greenhouse gases. Some efforts have been made to quantify the emissions from livestock manure stores [7][8] and from treatment systems [9][10][11]. The

1300 data collected have been limited, and therefore, it has not been possible to define the emission rates from wastewater purification. In the present study, bench-scale activated sludge units were operated with two types of aeration programs. The N20 gas concentrations during swine wastewater treatment were obtained to estimate total emission and to profile its release. TABLE 1 THE NUMBER OF LIVESTOCK AND ANNUAL PRODUCT OF THEIR WASTE NITROGEN AND PHOSPHATES IN JAPAN

(Tsuiki and Harada [4])

Type

Number LivestockWaste (Thousand tons) (Thousand) Feces Urine Total

Daily Cattle Beef Cattle Pig Layer Broiler Total

1,898 2,852 9,824 183,765 114,314

24,039 19,308 7,971 8,065 5,424 64,807

7,103 7,103 14,802

N and P in Waste(Thousand tons) Nitrogen Phosphorus

31 ,I 42 26,411 22,773 8,065 5,424 93,816

29,008

158.7 144.7 128.8 196.1 109.3 737.6

22.1 15.8 33.7 33.8 12.1 117.6

MATERIALS AND METHODS

Experimental design At 5 and 20°C conditions, the conventional and the intermittent aeration methods of wastewater purification were conducted with the bench-scale activated sludge unit (Fig. 1, 3 L operational volumes) under 0.5 kg m -3 d -1 of BOD loading condition, over 9 weeks. For the conventional process, a continuous aeration for 21 hours was adopted (ordinary method), while intermittent aeration was used at one-hour intervals. The units were set for a 24-hour cycle. The aeration periods started just after daily charging (0 time in Fig. 2). After the end of the aeration periods, the sludge in the mixed liquor was allowed to settle for two hours, and then the supernatant was discharged (Fig. 2). A mixture of swine feces and urine was used as influent wastewaters. The contents are shown in Table 2. Similar operational conditions for each run are as follows: 3 days of hydraulic retention time (HRT); 15-17 days of sludge retention time (SRT); 7000---9000 mg L 1 of mixed liquor suspended solid (MLSS); 0.5 kg m 3 d -1 of BOD loading; 1.2L min -1 3 L 4 aeration rate.

Discharge/Cha"cje ~..~a.s.~mple

Non /aeration

i: ~ f ~ i ..... b:,,:on. Brad q~m,3L,

Data k:;:n :

'~|

--

tAP llnk

'~

1

21

24

mH m lJl

e : . ~ ~

It. ~

Sediment

0

6

12

18

hours

i:PD Qju ~ i ~ . )

C:

j:It: D~ Iqp" ~=mm,'

Figure 1 :Composition of wastewater treatment apparatus

NEAP (Ordinaly)

Figure 2: Time chart of experimental operation

1301

TABLE 2 CHARACTERISTICSOF INFLUENTWASTEWATERAND EFFLUENTOF BOTHTREATMENTS (Average)

Items

Unit

Influent

BOD T-N

mgEl21L mglL refilL mg/L

1500.0 207.0 not detect 127.0

NOx-N

T-P

Effluent IAP NLAP(Ordinal.q) 2 El"C 5 "C 2 0 "C 5"C 19.5 12.7 9.6 30.g 94.5 54.5 32.0 100.4 19.6 6.5 6.5 16.7 43.0 48.3 46.3 41.7

Each unit was operated for a period longer than two SRTs (about 30 days) to obtain a steady-state condition. Also, the performance of each unit was evaluated for an additional two SRTs. Table 2 shows the average of the treatment data. The exhaust gases from the units were evaluated several days of wastewater treatment in the steady-state condition. These gases were collected from each head space (3 L) of the units opened (aeration periods) or closed (non-aeration periods) for 5-minute intervals during 24 hours (one treatment cycle).

Analysis The water qualities of the influent and effluent were analyzed twice a week for pH, TN, TP, NOx-N, and weekly for BOD. All analyses were conducted in accordance with the procedures of APHA [ 12]. Gas from each sampling point was automatically carried to the analysis apparatus through a Teflon tube (4 mm diameter). NH3, CH4 and N20 concentrations in the air samples were measured by Infrared Photoacoustic Detector (IPD, multi gas monitor type 1312, INNOVA, Copenhagen DK [ 10]) at 5-min. intervals (Fig. 1). Gas dried by electric cooler was used for the measurement of CH4 and N20 to improve the accuracy.

Method for calculating emission rate of each substances The rate of emission (E) for each substance (NH3, CH4 and N20) was computed from the concentration differences of each substance between inlet and outlet (background) air samples and the amount of flow-rate (0.0012 m 3 min -1, aeration periods) or headspace volume (3 L, non-aeration periods, sediment periods and discharge/charge periods). At the aeration periods: E (mg/5 min.) = (Cone. of outlet air (mg m -3) - Cone. of inlet air (rag/m-3)) x 5 x Flow-rate (m 3 hour 1)

...(1) Other periods: E (mg/5 min.) = (Cone. of outlet air (mg m -3) - Cone. of inlet air (mg m3)) x 5/60 x 0.003 (m 3 hour l )

...(2) * The 3 liters ofheadspace gas was completely replaced in one hour during which there were 12 gas samplings.

RESULTS AND DISCUSSION

Removal efficiencies of wastewater and CH4 and NzO emissions by both processes The average values of effluent characteristics in the processes are shown in Table 1. When the processes were rather high in MLSS concentration, high removal efficiencies (97.9 - 99.4%) for BOD were attained with both IAP and NLAP in all runs. While large differences in the removal of nitrogen between IAP and NLAP were observed at 20°C, the removal efflciencies for TN in IAP and NLAP were 84.5 and 54.8%, respectively. However, those removal efflciencies decreased with the decline of temperature (5°C). Removal

1302 efficiencies of IAP could solely satisfy the governmental effluent standard for BOD (120 mgL l daily average) and nitrogen (60 mgL 1 daily average). During steady-state conditions of wastewater treatment, exhaust gases from the units were evaluated. NH3, CH4 and N20 concentrations were measured at 5-min intervals by IPD throughout each treatment process (24 hrs) and emissions of each gas were totaled. The NH3 concentration in most of the exhaust gas in both processes was under 0.1 mg m -3, and the total emission of NH3 was considered negligible. The total emissions of CH4 from both processes were also low; for example, at the 20°C condition, NLAP and lAP exhaust was 1.33 and 2.05 mgCH4-C of CH4 throughout each process, respectively. These emission levels are equivalent to 0.14 and 0.22% of TOC in treated (influent) wastewater. This generation rate is kept to less than one-tenth the rate of emissions (2.6 %) generated from the stocked pig slurry rate earlier reported by Husted [8], compared to the organic matter base. N20 emissions during the NLAP treatment were 10.6 and 3.0 mg N20-N under the 20 and 5°C condition, respectively. In this experiment, the wastewater contained 207 mg of nitrogen. Thus, no less than 5% and 1.5% of the influent nitrogen was emitted as N20 gas using the conventional process under 0.5 kg m 3 d 1 BOD loading at each temperature. Less than 0.05% of the influent nitrogen was emitted as N20 gas IAP at both temperatures. Tsuruta [13] estimated around 0.92% of the nitrogen put in soil was lost as N20 in Japanese upland fields. At this level of N20 discharge, the conventional wastewater purification clearly has a serious impact on grovel warming when compared to agricultural usage.

GWPs of Swine wastewater treatment According to this experimental result, the GWPs [ 1] of swine waste treatment could be calculated as shown in Fig. 3. During one cubic meter of swine wastewater purification by the conventional process, about 1400 gCO2- 5000 gCO2 may generate as CH4 and N20 directly. These emissions could be reduced significantly about 77.1 gCO2 - 98.3 gCO2 by adequate manure contribution, and the adaptation of the intermittent aeration process for wastewater treatment.

(g C 0 2 eq) 4943.2

5000 4000 3000 2000 100C ~o(co2 ~ r4 (co2 ~¢~

C . . . . . . lAP/ LAP/ /20"C/ 5 "C 20"C 5°C

Figure 3: Grovel warming potentials generated directly from 1 m 3 of swine wastewater purification except CO2. (*1 m 3 of swine wastewater contain 950 g of total organic materials and 207 g of nitrogen.) N 2 0 emission pattern during both wastewater purification processes Significant differences were noted in the removal rate of nitrogen (Table 1) and N20 emission between NLAP (conventional process) and lAP for the same nitrogen loading (207 mg L l ) both at 20 and 5°C. Fig. 4 shows N20 concentration changes in exhaust gases from both processes.

1303 Sediment Discharge/Charge

Aeration

-,,. E

---

~" J,l~, 10

F i i i

i i

I

~ ~

!

~~m~i

: J

i i

~

m_.~ ~ i ~ m ~ l w ~ m ~ ,iI

,

1 ~-=

z

Im-~l~mleml~e

~wmm • O. I

:

,

.

.

~lmle.emene'

]

12 Time

.

i "

J

Ae~tton .

I ,,,l,

16

I ,,

,!,

21 2:3

(hrs) Sediment

Non eeroten .

bll

uimel~me-~m

6

0

.

9

.

.

e/C hwtJ e

.

.

~.........~.......i!i'iM

100

--, tO E

10

~

E

~

o~

o

20"O

o

bg

~c ~,P l r . ,

0

|

Ipmri

0,1

i,li|lIlilllll Iliillllll . . . . .

0

6

12

J 18

21

2:3

Time (hrs) Figure 4 : N 2 0 concentration in the exhaust gases and background air during wastewater treatment under Non Limited Aeration Process (4a, upper) and Intermittent Aeration Process (4b, under) In NLAP, a large amount of N20 was emitted during the initial stage of the aeration periods (0 to 3 hrs), which corresponded with the NOx-N decrease in the treated wastewater at low D.O. (0-0.5 mg 02 Ll). N20-N emission was stable at a relatively low level (9 mg m -3 at 20°C, Fig. 4 a). These data suggest that the emitted N20 mainly derived from a denitrification process. Zheng et al. [14], however, reported a high concentration of N20-N production during both the nitrification and the denitrification process at low D.O. (under 0.2 mg 02 L l ) conditions. During lAP, a high N 2 0 concentration was measured mainly during the non-aeration periods, and was relatively low (around 10 mg m -3 at 20°C, Fig. 4 b). The total emission of N20 was reduced by approximately 1/50 of the conventional process. Hanaki et al. [ 15] pointed out that a low COD/NOx-N ratio enhanced the N20 production. The incorporation of the intermittent low D.O. (non-aeration) periods in IAP

1304 might enhance denitrification and therefore avoid the accumulation of NOx-N. This seems to create a condition with a high ratio of organic substrate and NOx-N.

CONCLUSIONS

The results of the present study may be summarized as follows. 1) About 5% of the influent nitrogen was emitted as N20 gas using the conventional process under 0.5 kg m -3 d -l BOD loading and a 20°C condition. Most of the N20 was emitted during the first hours of aeration started just aider daily charging. 2) The emissions could be reduced by using the intermittent aeration process for wastewater treatment. Only Less than 0.05 % of the influent nitrogen was emitted as N20 gas during the intermittent aeration process under either temperature condition (5°C and 20°C). 3) The total emission of other harmful gases (NH3 and CH4) was negligible.

REFERENCES 1. 2.

Intergovernmental Panel on Climate Change (IPCC) (2001) Climate Change 2001 - Mitigation-, Section 3.6 Agriculture and Energy cropping, Cambridge University Press, UK Haga,K (1998a) Generation and regulation of methane and nitrous oxide from livestock waste. In: Emission control of the greenhouse gas in livestock farming, Report of investigation examination

enterprise for greenhouse-gas control technology concerning animal industry in Heisei 10 fiscal year, 3. 4. 5. 6. 7. 8. 9. 10.

11. 12. 13.

14. 15.

(1999) Japan Livestock Technology Association, 82-107 (Japanese) Law concerning the Appropriate Treatment and Promotion of Utilization of Livestock manure (Law No. 112 of July28, 1999), Japan Tsuiki M. and Harada Y. (1997) A Computer Program for Estimating the Amount of Livestock Wastes. The Journal of the Japanese Agricultural Systems Society 13(1) 17-23 Haga,K (1998b) Animal waste problems and their solution from the technological point of view in Japan. Jpn. Agric.Res.Q.,32 (3) 203-210 Osada T., Haga K. and Harada Y. (1991) Removal of nitrogen and phosphorus from swine wastewater by the activated sludge units with the intermittent aeration process, Water Research 25:1377-1388 Safley, L.M. Jr. and Westerman, P.W.,(1988) Biogas production from anaerobic lagoons. Biol. Wastes 23, 181-193. Husted S. (1994) Seasonal variation in methane emission from stored slurry and solid wastes. J. of Environ. Quality 23,585-592. Burton C.H., Sneath R.W. and Farrent J.W.(1993) Emission of nitrogen oxide gases during aerobic treatment of animal slurries Bioresource Technology 45,233-235 Osada T., Hans Benny Rom and Preben Dahl (1998) Continuous Measurement of Nitrous Oxide and Methane Emission in Pig Units by Infrared Photoacoustic Detection, Transaction of the ASAE. Vol 41, ppl109-1114. Osada T., Kuroda K., and Yonaga M. (2000) Nitrous oxide, Methane and ammonia emissions from composting process of swine waste. The Japanese Society of Waste Management Experts 2,51-56 APHA (1985) Standard Methods for the Examination of Water and Wastewater, 16th edition. American Public Health Association, Washington D.C. Tsuruta H. (1997) Emission rate of methane from rice fields and nitrous oxide from fertilized upland fields estimated from intensive field measurement for three years all over Japan, Res.Rep.Div.Environ. Planning. National Institute of Agro-Environmental Sciences Japan 13, 101-130 Zheng H., Hanaki K. and Matuo T.(1994) Production of nitrous oxide gas during nitrification of wastewater, Water Science and Technology, 30:133-141 Hanaki, K., Hong, Z. and Matuo, T.(1992) Production of nitrous oxide gas during denitrification of wastewater, Water Science and Technology, Vol. 26,No.5/6, 1027-1036

FUEL CELLS

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1307

HIGH EFFICIENCY CARBON AND H Y D R O G E N FUEL CELLS* FOR CO2 MITIGATED P O W E R M. Steinberg1, j. F. Cooper2 and N. Cherepy2 ~Brookhaven National Laboratory, Upton, NY 11973-5000 2Lawrence Livermore National Laboratory Livermore, CA 94551

ABSTRACT Hydrogen fuel cells have been under development for a number of years and are now nearing commercial applications. Direct carbon fuel cells, heretofore, have not reached practical stages of development because of problems in fuel reactivity and cell configuration. The carbon/air fuel cell reaction (C + 02 = CO2) has the advantage of having a nearly zero entropy change. This allows a theoretical efficiency of 100% at 700-800°C. The activities of the C fuel and CO2 product do not change during consumption of the fuel. Consequently, the EMF is invariant; this raises the possibility of 100% fuel utilization in a single pass. In contrast, the high-temperature hydrogen fuel has a theoretical efficiency of 50 kW). Figure 1 is a simple schematic of the technology.

2e-

2ev41

Air + CO2(from

H20 + CO 2

anode)

Hz + C O 32- ~ Hz O + C O z + 2 e " 1/2 0 2 + C O z + 2 e - --) C O 3 "" Overall: H 2 + 1/2 02 --~ 11120

Figure 1: Molten Carbonate Fuel Cell Scheme When H2 is fed to the anode side, it combines with the carbonate ions of the electrolyte to form steam and carbon dioxide and provides electrons as DC current. This DC current is normally inverted, using solid-state electronics, to produce AC for an external load. Simultaneously, the oxygen from the air and carbon dioxide (a slipstream from the anode reactions) are fed to the cathode, and react to replenish the carbonate ions consumed at the anode. The H2 is produced by the steam reforming of methane (natural gas). This reaction together with the shift reaction ultimately generates CO2 via CO. To ensure optimization of system efficiency, Ansaldo has heat

1327 integrated this process with the fuel cell reactions. Consequently, the fuel cell can generate electricity at high overall efficiencies, well above 40% for the complete system, methane to electricity. It is this characteristic that we wish to exploit. Another environmentally beneficial characteristic of the MCFC technology is its ability to transport carbon dioxide across the electrolyte, from the cathode side to the anode side of the fuel cell. Present on the anode side are typically H2, CO, CO2 and HzO. At the anode exit the gas composition includes un-reacted H2, steam and concentrated CO2 (from the cathode transfer and the reformate). The steam can be readily condensed, H2 can be separated and the residual CO1 is therefore available as a relatively pure stream for sequestration

The Hybrid Fuel Cell Scheme far C02 Capture The innovative scheme being proposed is a fuel cell hybrid based around Ansaldo's molten carbonate technology and a typical gas turbine. The aim of this integration is to maintain power generation on an existing gas turbine but ultimately with much reduced CO2 emission to the atmosphere. The use of MCFC will provide not only additional power generation capability at an increased level of efficiency, but also the means for concentrating and separating the COz from the conventional gas turbine. The exhaust from such a turbine would typically contain between 3 and 4%vol CO2. Overall, we believe that circa 50-60% of the CO2 emissions of conventional power plants could be separated with this scheme. In this study we have chosen to focus on a typical natural gas fired, small industrial gas turbine of nominal power output of 4.6 MW at standard operating conditions (15 degC, normal pressure at sea level). At this scale a single turbine would be generating over 3 tonnes per hour of CO2 (i.e. over 25000 tonnes per annum). We will also be investigating both an atmospheric and pressurized fuel cell system. A pressurized system can offer performance benefits in the fuel cell, notably increased power output that may generate additional value for the overall scheme. However, for the purposes of describing the concept, it suffices to focus on the atmospheric scheme (Figure 2). This hybrid concept has been modeled using Ansaldo's in-house expertise, based on several years of MCFC technology development and optimization. This includes not only the electrochemical processes of the cell, but also the engineering parameters such as pressure drop and heat integration. In our hybrid scheme, we have determined that the exhaust from a conventional 4.6 MW gas turbine can be fed to the cathode of a 1.6 MW atmospheric MCFC system. We believe that this ratio of between 2:1 and 3:1 in the relative power outputs of the two technologies in the hybrid scheme is scaleable e.g. a 10 MW gas turbine could be coupled with a fuel cell system in the 3 to 5 MW range. At the cathode, as a result of the electrochemical reaction with exhaust oxygen, the CO2 reacts to form carbonate ions and the resulting content of CO2 in the turbine exhaust stream is reduced from 4.7%wt (---3%vol) down to 2.3 wt% (~1.5%vol) i.e. a reduction of 50% across the fuel cell. Following transport of the carbonate ions across the electrolyte to the anode, the CO2 is released and mixed with the components from the reforming process (H2, CO and a small quantity of unconverted CH4). At the anode, the CO2 content of the reformate is increased from-25%wt at the inlet to -55%wt at the outlet. On a dry basis, this corresponds to a concentration of CO2 of about 85%wt. This anode exhaust, composed mainly of H20 and CO2, with some CH4, H2 and CO, is directed to a CO2 separation unit; the steam is condensed and the CO2 is separated for subsequent storage. The residual gas (CO, H2, and CH4) from this CO2 separation process is then recombined with the cathode off-gas in the catalytic burner, before release to the atmosphere. The combustion of CO in the catalytic burner generates additional CO2 in this exhaust stream, which obviously diminishes the overall reduction of the emissions. Nevertheless, in this un-optimized scheme, the CO2 released to the atmosphere can be reduced by circa 40% (i.e. from 3.2 tonnes per hour to 2.0 tonnes per hour, equivalent to a reduction of circa

1328 10500 tonnes per annum). If we then consider that the MCFC is also generating 1.6MW of power in addition to the gas turbine's 4.6 MW, then the CO2 emission per kWh produced is reduced by over 50%. These initial results gave us confidence that the MCFC hybrid system can act as a carbon dioxide concentrator [2].

Natural Gas

Water

1

I [ Evaporator

Gas Turbine 4.6MW

I GT/Cathode Exhaust

I Air

H2+ CO + CH 4

I

1 MCF~-1.6MW

~~wCO~r CO2 SEPARATION

F i g u r e 2: Hybrid Atmospheric Pressure MCFC Scheme for CO2 Capture

E X P E R I M E N T A L STUDIES Work Programme Objectives

The experimental investigation is being carried out at Ansaldo Fuel Cell S.p.A.'s test facilities in Genova, Italy. The work programme will confirm the accuracy of the above analysis and will seek to quantify: • • • •

The effect on the baseline fuel cell performance of varying CO2 and Impact of operating pressure on the system The optimal combination of conditions to maximize CO2 transport The effect of contaminants on performance and lifetime

02

concentrations at the cathode

The experiments are performed on single cells. The results can then be readily and reliably extrapolated to a large-scale fuel cell system.

Initial Experimental Results Any exhaust from a conventional combustion process can be considered as a source of CO2 for this tirol cell hybrid. However, the concentration of CO2 at the cathode is critical to the performance of the fuel cell,

1329 particularly if levels fall too low. Consequently, we have been quantifying the effect of varying CO2 levels on the fuel cell power output and CO2 transport across the electrolyte. In the above scheme, such gas turbines are fuelled either by natural gas (methane) or by No.2 fuel oil (diesel), and often employ dry low NOx burners to reduce emissions. The major constituents of the exhaust from such a turbine are Nitrogen (N2) 75%, Oxygen (02) 14%, Water (H20) 4 to 7% and Carbon Dioxide (CO2) 3 to 4% by volume. The initial results from these single atmospheric cell studies are illustrated in Figure 3. For a stand-alone molten carbonate fuel cell, CO2 levels at the cathode are typically maintained at circa 7-8%vol. At this concentration, the power density for a single cell was measured at circa 740 W/m 2 and the voltage at around 800 mV. This would correspond to an overall power output of 1.6MW for the MCFC unit alone (i.e. excluding the gas turbine power generation). Concentrations of CO2 above 7%vol were found to deliver only limited improvements in power density. 900 850

.....................................

"E 800 750

ii

= 700 °

1,47 MW

........................................................................................

. m

650

a. 600 550 .......

500 3

4

6

8

10

%mol C02 in Gas Turbine Exhaust

Figure 3" Single Cell Experimental Results At the lower, sub-optimal concentrations (1,000 K/s) from 596 to 1,040-°C in an argon atmosphere and are kept at the temperature for 10-20 s in the pyrolizer. Table 3 shows the physico-chemical characteristics of E. deglupta and C.oligodon. If tar is not produced and oxygen is consumed completely by combustion in the gasifier, the only three components of H2, CO and CH4 are estimated by the first order model [14]. Next, the experiment on the gasification is carried out by a thermogravimetric analyzer (Shimadzu, Model TGA-51). The char gasification using H20 and CO2 is the slowest reaction velocity among reactions in the gasifier. Thus, we examine the reaction velocity concerning the gasification. Firstly, a sample of about 20 mg is heated in a nitrogen atmosphere at a design temperature. Then char is produced in the furnace. Each design temperature in this experiment is 950, 1000, 1050 and 1100 °C. Secondly, the gasification occurs in the furnace temperature, which is in each design temperature. Char mass

1387 decreases by reacting with H20 (25vo1.%) and CO2 (65vo1.%). The variation rate X in each temperature is measured by the analyzer. The results of pyrolysis experiments and gasification experiments of char are shown in Table 4 here. Using the above experimental data, we evaluated BIGCC plant performance as Table 5. TABLE 3 PHYSICO-CHEMICAL CHARACTERISTICS

c [wt.%]" H [wt.%]*

o [wt.%]" S [wt.%]* N [wt.%]* Ash [wt.%]* Water Content [wt.%] Bulk Density [kg/m ~] Heating Value [kJ/kg]" *Dry-basis

E. deglupta 48.8 6.28 44.1 >0.1 0.16 0.63 38.9 380 25,900

C. oligodon 48.2 6.21 45.0 >0.1 0.15 0.35 20.0 780 19,600

TABLE 4 THE RESULTS OF PYROLYSIS AND GASIFICATION OF CHAR E. deglupta 1.41 3.86 0.87

H2 [mol/kg]" CO [mol/kg]* CH4 [mol/kg]* Gasification velocity IS-1]

dX= dt

1459ex/~-~-~) D-X)~

C. oligodon 2.74 2.68 1.82 dX

77701ex~-~/O-X~

*Yields of pyrolysis at 750°C TABLE 5 PERFORMANCEOF BIGCC Cold-gas eft. [%-LHV] Auxiliary[%] Net-Generating eff. [%-LHV] Annual Power [GWh/year]

E. deglupta 68.7 7.8 41.9 353.5

C. oligodon 64.0 16.3 40.0 655.1

LIFE CYCLE ANALYSIS IN A BIOMASS ENERGY SYSTEM This section deals with the above mentioned results on energy input and LCCO2 emissions in the two subsystems (Process 1 and Process 2). We evaluate energy balance ratio and LCCO2 emissions concerning the case of coal and biomass cases. Figure 3 shows the estimation results of E.B.R. and LCCO2 emissions. These results imply the following conclusions. First of all, energy balance ratio of a biomass system is lower than that of a coal power system. However LCCO2 of the biomass is smaller than the coal. Next, in the case of the biomass, energy balance ratio and LCCO2get worse as terrain degree increases. Finally, as Figure 3 indicates, an improvement of LCA index is found. For instance, about LCCOz emissions, it is 3.8 to 106.6 g-COz/kVvqain the case of E. deglupta, and on the other hand, is 1.3 to 62.8 g-COz/k'Whin the case of C. oligodon. Furthermore, although LCCO2emissions in the case of coal with CO2 removal equipment is 50.5 g-COz/k~Vh,if construction cost of the equipment is taken into consideration, that of the biomass will be superior generally.

1388 Consequently, nitrogen fixation of air, that is, selection of C. oligodon, has good influence on sustainable forest management. 20.00

1.0E+03

15.00 •So

r-'n ,S=

- - - ~ - - LC C 0 2 - E . d e g .

1.OE+02 '~"

ea

:

~

0

......

LCC02-Coal

- - -X- - - L C C 0 2 - C o a l r e m .

10.00 ,.~

~

E.B.R.-E.deg.

~

~ 1.OE+O1 .-1

5.00

~

E .B .R .-C .o li ~

E.B .R .-C oa 1

X

E.B .R .-C o a l r e m .

0.00

1.OE+O0 0

I

2

3

4

5

6

7

8

9 I0

Gradient [(leg.]

Figure 3: The estimation results of E.B.R. and LCCO2 emissions CONCLUSIONS

On the basis of this study it can be concluded that the biomass energy system, for example BIGCC system, can actualize the sequestration of CO/, that the improvement of the sequestration will be better by selecting C. oligodon, and that the system will be promising for developing countries as an environmentally friendly system or an alternative system to the fossil fuels in the future. As a future research subject, the continuous investigation about timber volume or nutrients circulation etc. in consideration of compound reforestation of C. oligodon will be important. REFERENCES Yamamoto, H., Yamaji, K. and Fujino, J. (1998) Energy Resources 19 2, 60. Thrhollow, A. E and Perlack, R. D. (1991) Biomass and Bioenergy 1 3, 129. Hanegraaf, M. C., Biewinga, E. E. and Bijl Ct V. D. (1998) Biomass and Bioenergy 15 4/5,345. Neilson, C. E. (1998) Biomass and Bioenergy 15 3,269. Ikeda, Y., Shinozaki, M., Suga, M., Hayami, H., Fujikawa, K. and Yoshioka, K. (1996) In: Input-output table for environment analysis. Keio University Economic Observation, Japan. 6. Abe, H., Niangu, M., Damas, K., Sam, N. and Kiyono, Y. (1998) PNG FRIBULLETIN 10, 53. 7. Abe, H., P. E Grierson, N. Sam, P. Nimiago, Dowaki, K. and M. A. Adams (2002) In: Basic research concerning nutrient circulation for cultivation energy crop in Papua New Guinea, RITE, Japan. 8. Nagasawa, T., Umeda, Y. and Li, L. (1993) Trans. JSIDRE 63 2, 121. 9. Hosoyamada, K. and Fujiwara, T. (1984) Trans. JSIDRE 52 4, 315. 10. Hosoyamada, K. and Fujiwara, T. (1984) Trans. JSIDRE 59 3,497. 11. Muraoka, H. and Miura, N. (1991) Trans. JSIDRE 59 3,283. 12. Smith, W. H. (1990) In: Air Pollution and Forest Second Edition. Springer Verlag, New York. 13. Dowaki, K., Ishitani, H., Matsuhashi, R. and N. Sam (2002) Technology 8, 193. 14. St~hl, K. and Neergaard, M. (1998) Biomass and Bioenergy 15 3,205. 15. Miura, K. and Mac, K. (1994) J. Chem. Eng 20 6, 733. 16. Abe, H., P. Kale and Kiyono, Y. (2000) PNG FRI BULLETIN 16, 36. 17. J. A. Duke (1983) In: Handbook of Energy Crops. http ://www.hort.purdue.edu/newcrop/duke_energy/Casuarina equisetifolia.html 18. D. Gauthier, H. G. Diem and Y. R. Dommergues (1985) Soil Biology and Biochemistry 17 3,375. 19. Philip J. Polglase, Mark A. Adams and Peter M. Attiwill. (1994) In, Measurement and Modeling Carbon Storage in A Chronosequence of Mountain Ash Forests. State Electricity Commission, Victoria

1. 2. 3. 4. 5.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1389

THE SYNTHESIS OF CLEAN FUELS FROM CO2 RICH BIOSYNGAS Kyu-Wan Lee and Jae-Sung Ryu Korea Research Institute of Chemical Technology e-mail: [email protected]

ABSTRACT In this work, the authors performed the Fischer-Tropsch reaction with biosyngas containing CO2, controlling the water gas shift reaction We carried out the reaction in a fixed bed, slurry bed and other reactor systems. However, in this paper, we report only the results from the fixed bed reactions. The reactions were carried out at both laboratory- and bench-scales. We also elucidated the causes of catalyst deactivation.

INTRODUCTION Recently, after COP 3 in Kyoto 1997, biomass was highlighted as an a sustainable energy source and an environmentally-friendly tool to reduce CO2. This is because biomass contains extremely low levels of sulfur and nitrogen, compared to coal and oil. The only way to synthesize liquid and solid paraffinic products containing alpha olefins with no sulfur and nitrogen from biomass is via FischerTrosch synthesis. Generally, for the F-T reaction, CO2 is eliminated to obtain pure syngas; however, in this work we didn't separate the CO2 and investigated the behavior of CO2 during the reaction in a fixed bed reactor. For a long time, the author(s) has investigated the catalytic hydrogenation of CO2 into hydrocarbons [1-3] and methanol/DME [4-5]. EXPERIMENTAL

Catalyst preparation [6] The catalyst was prepared in two steps, including co-precipitation and impregnation. The Fe-Cu-AI(Si) precursor was prepared by continuous co-precipitation from aqueous solution of metal nitrates with ammonium hydroxide solution, and the precipitate was impregnated with potassium carbonate by the incipient wetness method The catalyst composition was determined by ICP-AES to be 100Fe:6.6Cu: 15.7Al:K (Variable). Reaction The reaction was performed in a continuous fixed bed reactor. The catalyst (0.1-~1.0 g at the laboratory scale and 20-40 g in the bench scale reactions) was reduced in situ in hydrogen at 450°C for 24 hr. Then, the reaction was started with feed gas (variable composition) at a space velocity of 1800 ml/gcat.h under different pressures (10-30 atm) and temperatures (250-300°C). In the feed gas, Argon was added as an international standard gas for the GC analysis.

1390 The effluent gas from the reactor was periodically injected into an on-line GC by using two six-port valves. Ar, CO, CO2 and CH4 were analyzed by a thermal conductivity detector with a carbosphere column, while light hydrocarbons (C1-C8) were analyzed by flame ionization detector with a GS-Q capillary column.

Characterization of Catalysts The fresh, activated and deactivated catalysts were characterized by means of BET surface analysis, Mossbauer spectrocopy, XRD, XPS, TPR, TPDC and elemental analysis, etc.

RESULTS AND DISCUSSION

Characterization of catalysts. The catalysts were characterized by BET and adsorption of CO, CO2 and H2. The results are summarized in Table 1. Alumina addition increased the surface area and CO2 and hydrogen uptakes but in the silica supported catalyst, decreased remarkably. Alumina accelerated the K dispersion than Silica.

TABLE 1. CHARACTERIZATION OF CATALYSTS Catalyst

B E T area

CO2

CO

(p

(mZ/g)

Hz

mol/g)

FelCulAIlK(IO0/5/17/4) : Js,

95.5

209

FelCu/AIIK(IO0/6/16/4) : MW,

89.5

248

11.6

Fe/C u/SilK (100/6/16/4)

209.0

8.9

9.8

HzS exposed

47.0

4.4

The alumina supported catalyst converted CO in high levels, of >90%. Conversely, the silica supported one showed only 20% CO conversion and high methane (>45%) and low high fraction selectivities. Therefore, hereafter, we used Fe/Cu/A1/K catalyst for the reaction.

F- T Reactions It is impossible to obtain sufficient hydrogen gas by biomass gasification to react with co-produced CO and CO2 completely, because of its composition. The composition of biosyngas is variable and depends on the reaction conditions. Therefore, we tested many kinds of gases, composed of different ratios of CO/CO2/I--I2.

The effect of gas composition (hydrogen content) To test the catalytic activity for a model biosyngas (gas 1), hydrogenations of Ar/CO/COz/K/H2 (5/11/32/4/variable) were performed. From Table 2, it is clear that CO2 does not react, even at 300°C but it reacts in the presence of a stoichiometric hydrogen content, showing similar product selectivities. This means that the reaction proceeds through a reverse water gas shift (RWGS) reaction; namely, the products come from CO and not from CO2 [8].

1391 TABLE 2 COMPARISON OF BIOSYNGAS AND H2 SUPPLEMENTED GAS Conversion (%) CO

Olefin sel.(%) in C2-C4

Hydrocarbon distribution (C %) CO+CO

CO 2

CH4

C2-C4

C8+

C5-C7

2

H2-deficient feed: COTCO2 = 0.33, H2/(2CO+3CO2) = 0.44

82.78

0.26

21.18 12.62 39.19 21.89 26.31 84.92 ~ i5:33:i:i~i(2(::6¥3(~i5;) ~-i.................................................................................................................

....i3aia.,~ea-i~e-ea:-(~-(5;cr;

88.17

28.89

43.65

13.75

37.66

22.18

26.41

84.01

Reaction conditions: Fe/Cu/A1/K(100/6/16/4), 1 MPa, 300°C and 1800ml/g~t. • h. Balanced feed gas = 6.3CO/19.5CO2/5.5Ar/69.3H2.

Some representative F-T reaction results under various conditions are summarized in Table 3. From this table, we could induce following explanations (results). TABLE 3 REACTION RESULTS IN FIXED BED REACTION. c|t.

r2

e,-

cu-

F3

Fe-- C u -

AI- K (K-2) AJ- K ( K =

Co-

16 4)

*

•

69

19"59

t:~o°m~;;":022~ 2.0

1.0

2.0

1 0 : 4 0

F4

F,-

AI-

K (K=4)

10

*

69

20

F5

Fe-Cu.

AI.

K (K-$)

19

•

5i

2 0 1 0 : 4 0

F7

F,-

C,-

^I.

K (K-6)

19.

66

2.0

: I

F10

Fe-

Cu.

AI-

K (K=5)

lg

56

2.0

' 10

F11

: 4

Fe.

Cu-AI-K

4, 6 0

20

Fe-

Cu-

AI- K (K=8)

10

*

6o

2 o

: 1.0

Fe-Cu-AI-K

(K=4)

10

*

56

1 0

1.0

81

Fe-Cu-AI.K

(K-5)

.2

F.-

K (K-6)

I

50~

•

0

0 : 4.0

F12

A,

lg

0 : 4

F13

c.-

(K-S)

*

: I

: 4.0

0

20

: I

,.,m ,

P

Tim e

260

Z0

S01

94

275

1o

1oo

,,: ~

(,,,

xco

xcoz

SCH4

- 63.30

15,91

43,77

1064

9r12

-67.60

16 12

61 66

1636

.46

27

6

11

18

33

605

36

23

1661

42

! SCH6-

20

292

250

20

32

6042

• 74

61

6 62

260

20

210

96.53

-48

43

4 46

1638

4

265

20

165

96.63

-37

76

4

1650

431

-36

99

93

22

275

20

160

94

42

6.52

275

30

230

88

34

-5753

20

170

81

66

-26

20

71

95

14

• 6414

0 : 40

4

275

: 4.0

. 2

SCH2-

9621

: 25

1 0 : 4 0

o : I.o

Tern

276

s

276

20

220

31

4 29 S 09 1084

89

9

77

9 33

16

os

I

r

I

i

SCH6.

OSC.2-

29.60

45.90

1697

60.67

70.50

79

462

I 3974

78,31 79

96

74.36

60

01

76

63.26

67

7616

6454

1430

3 91

76.67

31

66

9 01

46

49

5495

30

62

26

70.26

32.79

21

46

36

18

06

39.82

7676

6076

The effect of potassium content It is well known that potassium is a good promoter in F-T reaction; thus, we also tested the effect of potassium as a promoter, focused on the aims as described in the Introduction. More than 2% of the potassium CO conversion and olefin selectivity of the C2-C4 fraction reached more than 80% and the methane selectivity decreased steadily below 10% over 4% of potassium-containing catalysts. By increasing the K content, the WGSR was suppressed and at high K content (8%) (see run F12 it did not occur below 275°C and 20 atm. This showed low methane and higher fractions produced in larger amounts, compared to the low potassium-containing catalysts (run F2). Conversely, at lower pressure, 10 atm, the WGSR proceeded significantly. Therefore, from the results, the preferred pressure is greater than 20 atm and the potassium content, above 4%.

Temperature and pressure effects At low temperature, 250°C, the CO conversion is not high, only 60.4% (run F5) and most of CO being converted to CO2; if the temperature is above 260°(2, the WGSR proceeded significantly. It is easily understood that the F-T reaction is an exothermic reaction (AH=-130--160KJ/mol). By increasing the temperature, the WGSR is suppressed (compare F5, 7, 10 and 11) but the product selectivities and olefin selectivity were very similar. At the same temperature, the high pressure prohibited the water gas shift reaction (compare F4 and F5); that means, at higher pressure, more CO is converted to longer chain products. At 30 atm, with a gas composed of CO/CO2/H2=1/1/2.5, most of CO is converted to CO2, meaning that the WGSR is prior to RWGSR, since the C8+ fraction and olefin selectivities were lower than the reactions at lower pressure (see Run 13). This may be attributable to the fact that at high pressure, the olefin is partially

1392 hydrogenated and chain propagation is prohibited by the shortage of CO, and the hydrogenation reaction proceeds to produce more methane.

Sulfur effect on catalyst An advantage ofbiosyngas is the extremely low sulfur and nitrogen contents in raw biosyngas, compared to gases from coal and oil. In catalysis, it is well known that sulfur damages the catalyst critically, and the sulfur content should be kept below 0.1ppm. Therefore, we tested the catalyst with different concentrations of HzS, namely 1, 3, and 5 ppm. The Fe/Cu/A1/K catalyst deactivated slowly, even at 1.0 ppm H2S concentration. The reason may be attributed to remarkably decreased BET surface area after exposure to H2S gas (see Table 1).

Long run test of catalyst. Our standard catalyst, Fe/Cu/A1/K=100/6/16/4, was verified as stable for more than 2,000 hr [7] in the case of CO2 hydrogenation under 300°C and 10atm. We also applied this to the F-T reaction of biosyngas. As you shown in Fig. 1, the catalyst activity was maintained for more 900 hr. We did not run beyond this because of experimental time schedule.

I0o, : :_-z _--_ : : :

:

-_:-

• :_

..:-

_- - :

:.

27oi1~

ZrOl~ • =m=o

,

~r~.

CO=

~.

,o

co,

i

co

!

i iiTi'iiiill"' ...."ii"'""

8

_

~f 0

*

"'"

. . . . . . . loo

20o

3oo

4oo

•.

:: . * * ° o

.-.? . . . . " '; , . , 5oo 6oo 7oo :: aoo

Time on s t r e a m (hr)

0 so

~0

lOOO

150

25o

o

100

2oo

300

400 soo r~oo 7oo i ~ T i m e on s t r e a m (hr) o 50

9oo 1so

~000 250

a) xeaction condition : P = 2.0 Mpa, T = 275/270 *C, SV = 1800rnl/g.h. b) reduction condition : H2 at 400 *C during 6hr c) biosyn gas composition : Ar/CO/CO2/H2= 5.83/26.53/13.27/54.36(vo1.%) d) coprecipitated catalyst composition : Fe/Cu/A1/K= 100/4.6/17.0/4 (wt. ratio)

Figure 1: Catalytic activity test for long run. Bench Scale Reactions

1)

Temperature profile

To accumulate technical data for the scaleup, we carried out bench scale reactions with different gas compositions; CO/CO2/H2=2/1/4 and 1/1/2.5 vol.%. To monitor the heat evolved during reactions, many thermocouples were installed at different heights along the fixed bed reactor.

1393 (A)

(B)

%,...,~

oa

A,.~ - .

"

E

T-T

T

z

0"70

40

SO

eO

IO0

120 ~40 1 "

leo

200

O0

.

.

Time [hr]

.

.

.

.

"~ ?'~/ ?5"" /

.

.

.

.

Temperature Profile [°C]

a) reaction condition : P = 2.0 Mpa, T = 270 °C, SV = 1800ml/g-h. b) reduction condition : H2 at 400 °C during 22hr c) biosyn gas composition : Ar/CO/CO2/H2 = 5.82/26.19/13.10/54.89(vo1.%) d) coprecipitated catalyst composition : Fe/Cu/A1/K = 100/6/17.0/4 (wt. ratio)

Figure 2: Temperature profiles at different height of the reactor and time on stream Figure 2 (A) & (B) show the temperature profiles at different heights of the reactor (A) and time on stream (B). The temperature at the inlet section increased significantly during the earlier stages. The maximum temperature difference between set and measured was about 40-50°C. To avoid the local heating of the catalyst bed, another efforts were required, for example, a more effective cooling system and/or dilution of the catalyst with quartz sand.

2)

Regeneration of deactivated catalyst

To discover the physical properties of the used catalyst, we extracted a wax covering on the surface and in the pores by extraction with light alkane, hexane, for two days, and finally oxidized at 400°C for 12 hr. However, the BET surface area was not recovered.

3)

SEM of Deactivated Catalyst

As the Author noted, catalyst deactivation [7] was examined. The causes of catalyst deactivation in biosyngas were crystallite size change and the change of elemental composition on the catalyst surface. Photo 1 supports the explanation, namely, surface morphology and crystallite size are changed from the inlet stage, compared to fresh catalyst.

3rd ~tage

Oullot stage

Photo 1. The SEM photos of catalysts of each stage and fresh

1394 CONCLUSIONS (1) We have developed the catalyst composed of Fe/Cu/A1/K for the F-T reaction ofbiosyngas which contains CO2. (2) We performed the F-T reactions under various conditions. The optimal reaction condition with gas 4, CO/CO2/H2=2/1/4 vol.%, was as follows; Temperature: 260-275°C, Pressure: 20 atm, Space velocity=1800 ml/g.h (3) We elucidated the catalyst deactivation. The causes could be attributed to composition change on the catalyst surface and change of crystalline size. (4) On the basis of laboratory-scale reactions, we carried out bench scale reactions. ACKNOWLEGEMENTS This work was supported by RITE/NEDO (Grant No: 99GP2) for 3 years. The Author is deeply appreciative for the financial support. REFERENCES

1. 2. 3. 4. 5. 6. 7. 8.

Lee, K. W., Nam S.S. et al., Appl. Organometal. Chem., 14, 794-798 (2000). Lee, K. W., Kim J.S. et al.,, Korean J. Chem. Eng., 18(4), 436-467 (2001). Lee, K. W., Kim H. et al.,, Study in Surface Sci.& Catalysis, 114, 407-410 (1998). Lee, K. W., Jun K.W. et al., Appl. Organometal. Chem., 2001, 15, 105-108. Lee, K. W., Shen W.J. et al., Korean J. Chem. Eng., 17(2), 210-216 (2000). Lee, K. W., Jun K.W. et al., Appl. Catal., A, 174, 231-238 (1998). Lee, K. W., Hong J.S. et al.,, Appl.Catal.,A, 218, (2001) 53-59. Lee, K. W., Riedel T., et al.,., Ind. Eng. Chem. Res., 2001, 40, 1355"1363.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1395

REDUCED CO2 MITIGATION COSTS BY MULTI-FUNCTIONAL BIOMASS PRODUCTION P. B6rjessonl'3 and G. Bemdes 2 1 Environmental and Energy Systems Studies, Dept. of Technology and Society Lund University, Gerdagatan 13, SE-223 62 Lund, Sweden 2 Dept. of Physical Resource Theory, Chalmers University of Technology/ Grteborg University, SE-412 96 Grteborg, Sweden 3 Author for correspondence

ABSTRACT

The CO2 mitigation cost when biomass replaces fossil fuels depends on several factors, such as the type of fossil fuel replaced, the energy systems involved, induced changes in the biospheric carbon stock, and the intensity and efficiency of the biomass production. Irrigation of energy crops, using nutrient rich municipal wastewater and drainage water, can lead to substantially improved productivity while at the same time addressing pollution of ground water and eutrophication. The cost of the biomass produced in such multifunctional biomass production systems will also be significantly reduced. Previous studies show that the COz mitigation cost when fossil fuels are replaced by biomass is often most sensitive to changes in fuel costs. Thus, a significant reduction in the biomass production cost will simultaneously lead to a substantial reduction in the CO2 mitigation cost. This paper shows that the CO2 mitigation cost could be significantly reduced, or even negative, when biomass from willow vegetation systems irrigated by nutrient-rich wastewater is utilised for replacing natural gas for heat and power production.

INTRODUCTION

The reduction of net CO2 emissions from substituting biomass for fossil fuels --and also the cost of such reductions-- depends on several factors, such as, the type of fossil fuel replaced, the energy systems involved, induced changes in the biospheric carbon stock, and the intensity and efficiency of the biomass production. Several studies have found that deficiency of water is often a growth-limiting factor in short rotation forestry, even in countries like Sweden with significant rainfall all year round [1]. Irrigation of energy crops, using nutrient rich municipal wastewater and drainage water, can lead to substantially improved productivity while at the same time addressing pollution of ground water and eutrophication of rivers, lakes and seas. Such multifunctional biomass production systems have been tested in large-scale field trials (Willow) in Sweden [2]. The cost of the biomass produced in these plantations will also be significantly reduced, or even negative [2,3]. Besides higher biomass yields, the reduced need for commercial fertilizers leads to lower cultivation costs. In addition, the cost of municipal wastewater treatment (considering nitrogen, phosphorus and sewage sludge treatment) is normally significantly lower in vegetation filters than in conventional treatment plants. Previous studies show that the CO2 mitigation cost when fossil fuels are replaced by biomass is often most sensitive to changes in fuel costs [4]. Thus, a significant reduction in the biomass production cost will simultaneously lead to a substantial reduction in the CO2 mitigation cost. This paper describes the possibilities of reducing biomass production costs by

1396 utilising willow plantations as vegetation filters for the treatment of nutrient rich wastewater, and how this cost reduction will affect the CO2 mitigation cost when natural gas is replaced, given heat and power production using various conversion technologies.

METHODOLOGY AND ASSUMPTIONS We define multi-functional biomass production systems as systems that, besides producing biomass, also generate additional environmental services. In this paper, we analyse willow plantations utilised as vegetation filters for the treatment of municipal wastewater and nitrogen polluted drainage water, located in Southwest, Southeast and Central Sweden, respectively. The economic value of the additional environmental services has been estimated by using two different methods. When there exists a relationship between an environmental service and a change in, for example, cultivation cost, this relation is used for valuation. One example is increased crop yields through irrigation of wastewater. When no such direct cost relation exists, the substitution cost method has been used. The substitution cost describes the cost of providing the same environmental service, but in another relevant and cost-efficient way [3]. One example is the cost of reducing nutrient leaching through the restoration of wetlands, which have the same purification function as willow vegetation filters in cleansing nitrogen polluted drainage water. We analyse the total reduction in CO2 emission (fuel-cycle CO2 emissions) by substituting natural gas for the cogeneration of power and heat, and for stand-alone power production, respectively. Cogeneration systems typically improve the efficiency of fuel use and reduce costs compared with the separate production of heat and power. The heat sinks available, however, limit the application of such systems. To make possible the comparison between the separate production of heat and power and cogeneration, we must consider both the energy carriers produced. This can be achieved by expanding the reference entity to include both power and heat in the analysis [4]. Here, we use the reference entity 1 MWh of power and 1 MWh of heat, since this is the highest ratio of produced power to heat for the cogeneration technology studied. For the additional power required for cogeneration plants with a power to heat ratio < 1.0, the power is assumed to be produced in condensing plants. The following systems are included:

Cogeneration of power and heat • A natural-gas-fired cogeneration plant (Cogen-NG) - Reference energy system • A natural-gas-fired condensing plant and a biomass-fired cogeneration plant with steam turbine (CogenBio-ST) • A biomass-fired cogeneration plant with integrated gasification and combined-cycle technology (CogenBio-IGCC) Stand-alone power production • A natural-gas-fired condensing plant (Condense-NG) - Reference energy system • A biomass-fired condensing plant with steam turbine (Condense-Bio-ST) • A biomass-fired condensing plant with integrated gasification and combined-cycle technology (Condense-Bio-IGCC) A more detailed description of the technologies studied, including capacities, efficiencies and the costs, is given in Gustavsson and Brrjesson [4]. The energy content of the fuels is defined as the LHV. All costs refer to 1997 when the average exchange rate was US$1 = SEK 7.64. The annual capital costs have been calculated using 6% real discount rate. The price of natural gas for cogeneration and for condensing plants is assumed to be US$ 4.7 and US$ 3.9/GJ fuel, respectively [4]. Domestic Swedish taxes have been excluded from the analyses.

1397 W I L L O W V E G E T A T I O N F I L T E R CHARACTERISTICS

Treatment efficiency The purification efficiency of willow vegetation filters has been demonstrated in several countries, e.g. Sweden, Poland, Denmark, and Estonia [5]. When wastewater percolates through the soil, the welldeveloped root system takes up 75-95% of nitrogen (N) and phosphorus (P) in the wastewater [6]. The nutrient content in municipal wastewater corresponds fairly well to the nutrient requirements in willow cultivation. An annual municipal wastewater load of 600 mm/ha, containing about 100 kg N, 20 kg P, and 65 kg K, will supply, not only the demand for water, but also the demand for nitrogen and other macronutrients [5]. The concept of using willow vegetation filters for the treatment of nitrogen-polluted drainage water has been tested in a large-scale field trial in southern Sweden since 1993 [7]. Here, a storage pond received drainage water from surrounding intensively cultivated land, which was subsequently used for irrigation of a willow plantation, using a furrow system for water distribution. Results from the field trial show that the nitrate concentration in the drainage water was significantly reduced after passing through the vegetation filter [7].

Biomass yield response A previous study by Lindroth and Bfith [1 ] shows that water deficit is often a limiting factor for high productivity in willow cultivation, even in countries like Sweden with significant rainfall all year round. The regional variation in biomass yields could be significant due to differences in water supply during the vegetation period. For example, the willow yield in conventional rain-fed plantations in the southeast of Sweden is normally around 50 to 60% of that in the southwest of Sweden, due to a lower rainfall in the summer season. Thus, the biomass yield response from wastewater irrigation will increase with a decrease in precipitation during the vegetation period. An estimation is that the biomass yield response from wastewater irrigation (compared with rain-fed) will vary from +30 to + 110% in Swedish willow plantations, due to the geographical location (Table 1) [2]. TABLE 1 ESTIMATED BIOMASS YIELD IN CONVENTIONALRAIN-FEDAND IN WASTEWATERIRRIGATEDWILLOW PLANTATIONS, RESPECTIVELY,IN DIFFERENTSWEDISH REGIONSa Region

Biomass yield Conventional rainWastewater fed plantations irrigated plantations dry Mg/ha, yr dry Mg/ha, yr 14 18

Southwest (SW) Southeast (SE) 8 Central (C) 10 a Estimationsbased on data from Lindrothand Bath [1].

Yield increase

dry Mg/ha, yr +4

+30

17

+ 9

+ 110

16

+6

+ 60

ECONOMIC VALUATION

Municipal wastewater treatment The economic value of municipal wastewater treatment in willow vegetation filters is here based on (i) reduced treatment cost compared with conventional N, P and sewage sludge treatment, and (ii) reduced cultivation costs. Results from previous studies show that the wastewater treatment cost can be reduced by, on average, 40%, or US$ 6.5/kg N, when wastewater produced during the summer months is treated in willow vegetation filters [8]. If also wastewater produced during the winter months is treated, the treatment cost will be reduced by, on average, US$ 2.6/kg N, compared with conventional treatment. This lower reduction in treatment cost in the whole year option, compared with the summer option, is due to the need for intermediate storage ponds during the non-growing season in the whole year option. The calculations

1398 include irrigation (equivalent to a N supply of 100 kg N/ha, yr) through a pump-pipe system with a maximum length of the feed pipe to the willow plantation of 5 km, and the cost of all technical equipment, labour and energy use. When also the value of the reduced generation of sewage sludge is included, the treatment costs will be reduced further by around US$ 1.6 and US$ 0.8/kg N for the whole year and the summer options, respectively [2]. Wastewater irrigation will reduce willow cultivation costs by increased biomass yields and by making commercial fertilisers superfluous. The value of these benefits, compared with conventional willow cultivation, is estimated to be from US$ 2.2/kg N in the southwest of Sweden, up to US$ 3.7/kg N in the southeast of Sweden, due to variations in crop yield response (see Table 1) [2,8].

Treatment o f poUuted drainage water The economic value of the treatment of polluted drainage water in willow vegetation filters is here based on (i) reduced cultivation costs, and (ii) the alternative treatment cost using restored wetlands. Restoration of wetlands is a cost-efficient method of reducing eutrophication and is a commonly used method in Sweden today. The marginal cost of nitrogen mitigation through restoration of wetlands has been estimated by Gren [9] to vary from US$ 2.6 to US$ 7.8/kg N, depending on local conditions (an average cost of US$ 5.2/kg N is used here). Like in the case of municipal wastewater irrigation, the reduced cultivation costs are based on increased biomass yields and reduced costs for fertilisers. Cost calculations of drainage water irrigation include irrigation through a pump-pipe system, storage pond, and the cost of all technical equipment, labour and energy use [8]. The size of the storage pond needed is estimated to vary regionally depending on the annual precipitation and the nitrogen content in the drainage water [2]. All drainage water produced during the whole year is assumed to be treated (equivalent to the "whole year option "considering municipal wastewater irrigation). In drier areas with relatively high nitrogen leaching, e.g. Southeast Sweden, smaller storage ponds are needed per hectare of willow vegetation filter in order to supply the nitrogen equivalent to 100 kg N, than in areas with higher precipitation and lower nitrogen leaching, e.g. Central Sweden. In these areas, the irrigation cost is calculated to, on average, US$ 6.9 and U S $ 1 2 / k g N, respectively.

Total biomass costs The total costs of biomass produced in willow vegetation filters, including the value of the water treatment, are summarised in Table 2. For comparison, the cost of biomass in conventional willow plantations is also shown. TABLE 2 TOTAL BIOMASS COSTS IN CONVENTIONAL WILLOW PLANTATIONS AND IN WILLOW VEGETATION FILTERS IN DIFFERENT SWEDISH REGIONS, INCLUDING THE ECONOMIC VALUE OF THE WATER TREATMENT a Region

Conventional willow plantations

Willow vegetation filters b

Municipal waste Municipal w a s t e Treatment of water treatment water treatment nitrogen polluted summer option c whole year option d drainage water e US$/GJ US$/GJ US$/GJ US$/GJ Southwest (SW) 4.7 -0.81 1.0 5.0 Southeast (SE) 5.3 -1.2 0.61 4.2 Central (C) 5.0 -0.92 0.92 7.2 a Including a transportation cost of US$ 0.8/GJ, which is equivalent to a transportation distance of 40 km [4]. b The wastewater and drainage water application corresponds to 100 kg N per ha. ¢ Summer option means treatment of wastewater produced during the vegetation period. d Whole year option means treatment of wastewater produced during the whole year and thus includes intermediate storage ponds. e Including intermediate storage ponds. The alternative cost of nitrogen mitigation is based on restoration of wetlands.

1399 CO2 MITIGATION COST

In Figure 1, the CO2 mitigation costs are shown when biomass replaces natural gas for the cogeneration of heat and power and for stand-alone power production, respectively, and how the mitigation cost varies due to changes in biomass cost. The CO2 mitigation cost is lowest for cogeneration systems using IGCC technology, followed by stand-alone power production using IGCC and stem turbine technology, respectively, when biomass from conventional willow plantations is replacing natural gas. For these three systems, the CO2 mitigation cost varies between US$170-300/t C, due to the conversion technology and the location of willow cultivation. The CO2 mitigation cost for cogeneration using stem turbine technology is significantly higher. Using nitrogen polluted drainage water for irrigation of willow plantations will lead to reduced biomass costs when applied in Southeast Sweden, resulting in a CO2 mitigation cost around US$150/t C (excluding Cogen-Bio-ST). However, in Southwest Sweden, and especially in Central Sweden, the biomass cost, as well as the CO2 mitigation costs, will be higher due to the need of larger storage ponds and thereby higher irrigation costs. When municipal wastewater is used for irrigation in willow plantations, the biomass cost, as well as the CO2 mitigation cost, will be significantly reduced. The CO2 mitigation cost turns negative when the biomass cost is below US$ 0.5-1/GJ, which will be the case when willow plantations are utilised for wastewater treatment considering both the summer and the whole year options. Considering the summer option (excluding storage ponds), the biomass cost and the CO2 mitigation cost will be reduced further, leading to negative CO2 mitigation costs (US$ -210 to -140/t C). The lowest costs refer to willow production in the southeast of Sweden where the highest biomass yield response from wastewater irrigation is achieved.

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Figure 1: Commercial Biomass Energy In the Global Energy The effect of modem commercial biomass on land use ranges from modest, providing farmers a new commercial crop, in the MiniCAM B2 0.5% productivity growth rate reference case, to the most important land-use activity on earth, MiniCAM B2 550 1.5% agricultural productivity growth rate, Figure 2. The MiniCAM B2 reference case scenario implies an increasing fraction of land coming under direct agricultural management. This in tum leads to emissions from deforestation. Deforestation rates depend on time and the rate of technology improvement. In the MiniCAM B2 0.5% productivity growth case, emissions rise until the middle of the century, eventually reaching four billion tons of carbon per year. Beyond the middle of the century the rate of change in land use slows and finally halts dropping deforestation emissions to zero. Against this background the imposition of a constraint on 4 Though this result requires hydrogen and fuel cell technologiesto improve relative to present technologies. As Edmonds, et al. 2002 discuss, if this progress lags, the hydrogen market may never form.

1431 emissions has the effect of expanding the demand for land to provide biomass energy. This in turn fuels the continued expansion of managed lands into the unmanaged ecosystems and sustains the rate of landuse emissions about a quarter century beyond the non-climate control case. When agricultural productivity increases to 1.5% per year, land-use emissions are significantly reduced. The maximum emissions are relatively stable through the middle of the century at which point they begin to decline and eventually enter a regime of net global reforestation. The effect of a constraint on the concentration of CO2 has a similar effect at 1.5% agricultural productivity growth to its effect at 0.5% productivity growth. That is, it delays the decline in emissions in the second half of the century. The reason that land-use emissions are relatively insensitive to the constraint in the first half of the century is the fact that carbon values are relatively low and the demand for land for commercial biomass remains small. The interaction between agricultural productivity, food prices and climate change is similarly noteworthy. In the absence of climate change, crop prices decline continuously over the course of the century. MiniCAM B2 100% 90% 8O% 70% 60% 5O% 40% 3O% 20% 10% 0%

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Figure 2: Managed and unmanaged land use--1990 to 2095 The decline goes on somewhat faster when agricultural productivity is higher, but unless productivity growth falls below 0.5% per year, crop prices end the century at a lower level than they began the century and with a 1.5% productivity growth rate are about one third lower. The imposition of a ceiling on the concentration of CO2 of 550 ppmv alters that pattern. The competition for land by commercial biomass leads to an increase in land values and land rents, reducing the extent of crops, pastures and forests, and which in turn raise crop prices. The rise in crop prices is highly sensitive to agricultural productivity growth rates. When agricultural productivity growth rates are 0.5% per year, year 2095 crop prices are double 1990 prices. When agricultural productivity growth rates are 1.5% per year, year 2095 crop prices are very near their 1990 levels.

1432 INTERACTIONS WITH CARBON CAPTURE AND DISPOSAL In the analysis reported above the ability to capture carbon from waste gas streams and dispose of it in permanent, reservoirs was not available. While issues surrounding this technology are discussed in greater detail in Edmonds, et al. (2002), some interesting interactions occur with commercial biomass. The presence of carbon capture and disposal technologies makes it possible for fossil fuels to be used while emitting carbon at dramatically lower rates 5. In addition, it opens the possibility that carbon can be removed from commercial biomass creating an energy form which effectively removes carbon from the atmosphere net. While interactions are too many and too varied to report in this brief paper, it is worth noting that the availability of carbon capture and disposal technology dramatically reduces the marginal value of a ton of carbon, cutting it by two-thirds. This reduces the extent of land area needed for commercial biomass, reducing the pressures to deforest. The upward pressure on crop prices exerted by the requirement to stabilize CO2 concentrations is also significantly reduced. Nevertheless, when the concentration of CO2 is stabilized biomass remains as attractive a feedstock for hydrogen production in the presence of carbon capture and disposal technology as without, owing to the fact that biomass derived hydrogen can be a negative-emission fuel.

FINAL THOUGHTS The value of biotechnology in stabilizing the concentration of CO2 in the atmosphere is substantial by any number of metrics. The value of a ton of carbon is reduced by a third when agricultural productivity growth rates rise from 0.5% per year to 1.5% per year, while food grain prices are reduced by almost half. The 1.5% per year productivity growth rate decreases the intrusion into unmanaged ecosystems by half compared with the 0.5% per year agricultural productivity growth rate. To the extent that biotechnology can raise agricultural productivity, including productivity in commercial biomass crops, traditional crops, pastures, and forests, the cost of stabilizing the concentration of CO2 in the atmosphere can be reduced.

REFERENCES 1. Edmonds, J., J. Clarke, J. Dooley, S. H. Kim, S. J. Smith. 2002. "Stabilization of CO2 in a B2 World: Insights on The Roles of Carbon Capture and Disposal, Hydrogen, and Transportation Technologies," submitted to Energy Policy, Special Issue, J. Weyant and R. Tol (eds.). 2. Edmonds, J., M. Wise, R. Sands, R. Brown, and H. Kheshgi. 1996. Agriculture, Land-Use, and Commercial Biomass Energy: A Preliminary Integrated Analysis of the Potential Role of Biomass Energy for Reducing Future Greenhouse Related Emissions. PNNL-11155. Pacific Northwest National Laboratories, Washington, DC. 3. Nakicenovic, N., et al. 2000. Special Report on Emissions Scenarios. Cambridge University Press, Cambridge, United Kingdom. 4. United Nations. 1992. Framework Convention on Climate Change. United Nations, New York. 5. Wigley, T.M.L., R. Richels & J. A. Edmonds. 1996. "Economic and Environmental Choices in the Stabilization of Atmospheric CO2 Concentrations," Nature. 379(6562):240-243.

5In this analysis the carbon removal efficiencyis assumed to be 90%.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1433

THE CONTROLLED EUTROPHICATION PROCESS: USING MICROALGAE FOR CO2 UTILIZATION AND AGRICULTURAL FERTILIZER RECYCLING.

J.R. Benemann l, J.C. Van Olst 2, M.J. Massingill 2, J.A. Carlberg 2, J.C. Weissman 3, and D.E. Brune 4 1Consultant, 3434 Tice Creek Dr. No. 1, Walnut Creek, California, 94595, USA 2Kent SeaTech Corp., 11125 Flintkote Ave., Suite J, San Diego, California, 92121, USA 3SeaAg, Inc., 705 27th Ave. S.W., Suite 5, Vero Beach, Florida 32968, USA 4Agficultural & Biological Engineering Dept., Clemson University, Clemson, South Carolina, 29634, USA

ABSTRACT

In 1960, Oswald and Golueke [1] presented a conceptual techno-economic analysis, "The Biological Transformation of Solar Energy", proposing the use of large-scale raceway ponds to cultivate microalgae on waste nutrients and then to ferment (anaerobic digestion) the algal biomass to methane fuel. The methane was to be converted into electricity, with the CO2-containing flue gas and the nutrient-containing digester effluents recycled to the ponds to support further algal production. Over the past forty years a great deal of research has been carried out on this and similar concepts for microalgae fuels production and CO2 utilization. However, significant technical challenges have limited the practical application of this technology: the difficulties of maintaining selected algal species in algal mass cultures, the lower-than anticipated biomass productivities and methane yields, and, in particular, the high costs of harvesting the algal biomass. These limitations could be overcome through further research and technology development and by integrating biofuel production with wastewater treatment and nutrient recovery, providing for additional economic and environmental benefits, in particular where relatively large scales are possible. One potential site for such a large-scale integrated process is the Salton Sea in Southem Califomia, a shallow (average 10 m depth) large (900 km 2) inland lake located below sea level and, thus, without an outflow. About 10,000 tons of nitrogen (mostly as nitrate) and phosphorous (as phosphates) are discharged annually into the Salton Sea by three rivers that drain wastewaters from population centers and drainage waters from large tracts of irrigated agriculture. Removal of nutrients from these inflows is required to avoid eutrophication of this large lake with resulting massive algal blooms, fish kills and other environmental impacts. Nutrient capture could, in principle, be accomplished with 1,000 hectares of algal pond systems, assuming a production of 100 tons of dry weight biomass per hectare per year (t/ha/y) and a typical 10 % N and 1% P content in the harvested algal biomass. This biomass could then be converted into biofuels with the residual sludge used in agriculture for its fertilizer value. As stated above, a major limitation of such a process is the harvesting of the algal biomass, which is expensive using current technology. The "Partitioned Aquaculture System" (PAS), developed at Clemson University, integrates microalgae production with fish aquaculture in a process that promotes a vigorous algal culture of desirable species and converts these into a sedimentable biomass through the production of fish fecal pellets. An adaptation of the PAS, the "Controlled Eutrophication Process" (CEP), has been designed and is being tested by Kent SeaTech Corp. to achieve the objective of nutrient removal from the Salton Sea influents. The CEP, by producing a combination of valuable outputs, including fuels, fertilizers and fish, could help to affordably manage the Salton Sea environmental quality while also abating substantial quantities of greenhouse gases.

1434 INTRODUCTION: MICROALGAE APPLICATIONS IN ENVIRONMENTAL PROTECTION. Microalgae ponds have been used for several decades for the treatment of municipal and other wastewaters. In these, so called "facultative ponds", the microalgae mainly provide dissolved oxygen for bacterial decomposition of the organic wastes [2]. The major limitations of this technology are the relatively large areas required and the high cost of removing the algal cells from the pond effluents, using chemical flocculation-sedimentation, centrifugation or other means. Shallow (< 0.5 m depth) raceway-type ponds, with channels and mechanical mixing ("high-rate ponds"), were introduced in the 1950's [3] allowing much higher productivities and thus higher loadings than the conventional unmixed, deeper (> 1 m deep) facultative ponds. High rate ponds also exhibit higher algal cell densities, making algae removal, that is harvesting, an even more critical requirement. Paddle wheel mixing provides a controllable and flexible mixing regime that allows management of the pond culture to promote algal cells that tend to spontaneously flocculate and settle [4]. However, it has not been possible to demonstrate such a "bioflocculation" processes with the high reliability required for algal harvesting from municipal wastewater treatment or similar applications. Thus, in current design practice, large settling or "maturation" ponds follow the high rate ponds, just as in the case of facultative ponds, though these are only partially effective in reducing algal solids in the effluents. This greatly increases the area ("footprint") of such systems and often prevents the discharge of the treated pond effluents to rivers or lakes, requiting their use in ground water recharge, irrigation or similar applications. Development of more intensive, smaller footprint, microalgal wastewater treatment processes based on high rate pond technology and low-cost algal harvesting remains a significant R&D challenge. One process that can accomplish this goal is the patented "Partitioned Aquaculture System" (PAS) [5, 6, 7], now being tested at the Salton Sea in a variation termed the "Controlled Eutrophication Process", further described below. Microalgae have also been extensively studied in other environmental applications. The removal of heavy metals from wastewaters with microalgae has been studied and commercial applications with immobilized algae were reported, though these could not compete commercially with ion exchange resins [8]. The removal of residual nutrients, specifically N and P from wastewaters, so-called "tertiary treatment", has also been investigated. A variety of processes have been proposed, from attached algal cultures to the cultivation of thermophilic species in cooling reservoirs [9]. Microalgae are excellent for nutrient removal processes, with typical contents of N and P of about 10 and 1% respectively, on a dry weight basis, several-fold higher than for higher plants. Also, microalgae cultures are able to reduce residual nutrient concentrations to vanishingly low levels and even allow for a significant variability in N:P ratios, from about 3 to 30 N for each P, on a weight basis, depending on which is the limiting nutrient. Finally, microalgae cultures have been proposed as a method for fixation of CO2 and production ofbiofuels, of interest in greenhouse gas abatement. The first conceptual development of this idea was by Oswald and Golueke in 1960 [ 1], who prosposed a very large-scale system with dozens of large (40 hectare) high rate ponds, with the biomass harvested by a simple flocculation-settling step, and the concentrated algal sludge anaerobically digested to produce biogas (CH4and CO2). The biogas was to be used to generate electricity and the flue gas CO2, along with the nutrients in the digester effluents, used to grow more algae. Make-up water and nutrients (C, N, P, etc.) would be provided from municipal wastewaters. Their conceptual cost estimates suggested electricity generation costs similar to those projected at the time for nuclear power. A more detailed, design and engineering study of this concept [ 10] concluded that with favorable assumptions, in particular availability of a low-cost harvesting process, such systems could produce biogas competitively with then projected fossil fuel prices. From 1980 to 1995 the U.S. R&D effort in microalgae biofuels production centered on the Department of Energy (U.S. DOE) sponsored "Aquatic Species Program" (ASP), which aimed at producing algal oils for production ofbiodiesel [ 11 ]. More detailed engineering design and cost analysis studies were carried out by the ASP during the 1980's [12, 13], again with many favorable assumptions, in particular the achievement of very high productivities. A 0.25 hectare pilot plant in New Mexico [ 14] demonstrated the feasibility of outdoor microalgae cultivation on saline waters and efficient CO2 capture. However, the projected long-term R&D required for development of such dedicated biofuel production processes, led, among other factors, to the wind-down of the ASP. In Japan a very large (> US$200 million) govemment-sponsored program to develop microalgae biofixation of CO2 for greenhouse gas abatement, involving many private companies, was carried out during the 1990's. That program focused on closed photobioreactors, in particular optical fiber systems, and co-production of

1435 high value products [ 15]. Similar concepts are currently being developed in the U.S. with DOE support [ 16, 17]. Also during the 1990's several electric utility companies in Japan carried out microalgae R&D projects, including cultivation of microalgae on power plant flue gases in small ponds [18]. Most Japanese R&D efforts ceased by 2000, due to the very high costs of closed photobioreactors and the minimal potential of high-value co-products, although some microalgae biofixation R&D continues [ 19, 20, 21]. Recently, an "International Network on Microalgae Biofixation of CO2 and Greenhouse Gas Abatement" was formed comprising international energy agencies and companies to foment and coordinate R&D activities in his field [see Pedroni et al., in These Proceedings]. Microalgae biofixation of CO2 for greenhouse gas abatement requires open pond systems, as closed photobioreactors are much too expensive. However, even simple open pond cultivation systems are presently too costly for dedicated biofuel production, and such processes must include other co-products or co-services, such as wastewater treatment, fertilizer production and/or feed/food production, to make them economically competitive. One specific application is the use of microalgae to remove N and P from wastewaters, as discussed next. THE SALTON SEA AND THE CONTROLLED EUTROPHICATION PROCESS. Irrigation in desert or semi-desert environments often leads to soil salinity problems, due to surface evaporation, requiring drainage of the fields, thereby producing so-called agricultural drainage waters. These are typically high in salts and nutrients, principally nitrates and inorganic and organic phosphates. In Southern California, agricultural drainage systems used in the Coachella and Imperial valleys drain into the large, about 900 km 2, Salton Sea. The current Salton Sea began with the accidental flooding of the below sea-level Salton Sink in 1904 with Colorado River water. As the Sea has no natural outlet, salinity has increased through evaporation of the runoff and drainage from agriculture and settlements, presently reaching about 46 parts per thousand (ppt). The major sources of inflow to the Sea are (% of total): the Alamo River (45%), New River (45%) and the Whitewater River (10%). Total inflow, including runoff, ranges from 1 to 1.5 billion m 3 per year. As the Sea has increased in salt content it has seen a transition of ecosystems from freshwater to brackish, now reaching the tolerance limits of most fish. These environmental problems are exacerbated by high nutrients inputs, principally nitrates and phosphates. Proposed solutions to the salinity increases include evaporative ponds, desalinization plants and pumping saline waters to the Gulf of California. Evaporative ponds would require up to 20% of the total lake area, the other options are very expensive and energy consuming. One management plan is to install dikes within the sea near the freshwater inputs, creating fresh to brackish ecological zones C ecotones", Figure 1), where fisheries and wildlife could prosper, with the center of the sea continuing to increase in salinity. However, the large present inputs of N and P into the lake, about 10,000 and 1,000 tons/year (t/yr) respectively, create hyper-eutrophic conditions resulting in severe fluctuations in dissolved oxygen concentrations, leading to massive fish kills. These problems would not be remedied by the proposed salinity control measures alone. To reduce the nutrient loads to this lake, an adaptation of the PAS, Partitioned Aquaculture Systems, developed at Clemson University by the senior author (DEB) and colleagues [5, 6, 7], is proposed to be sited near the three main inlets to the Sea (see "PAS" in Figure 1). This modified process, now called the "Control!ed Eutrophication Process" (CEP), is in concept similar to the conventional PAS, in which algae are grown in typical high-rate ponds (raceway, paddlewheel mixed), with the algal culture passed through separate zones containing planktivorous fish, such as Tilapia. The fish convert most of the algal biomass into settleable solids (feces and pseudo-feces), which can be readily removed by fast settling ("high rate sedimentation"). Residual algal solids would be processed further by Tilapia or similar fish cultures and polished by chemical flocculation. The algal and fecal solids would be recycled to agricultural land as fertilizers, preferably after anaerobic digestion to produce biogas, a mixture of CH4 and CO2. Development of this process has been initiated by Kent SeaTech Corp. with two pilot-scale 3,000 m 2 high-rate pond ASP systems located next to the Whitewater River (near the north-west end of the Salton Sea, see Figure 2). The multiple products that would be generated from such a process, in particular the relatively high value fish, in addition to payments received for nutrient removal, would make such a process economically appealing and a candidate for early implementation. To remove most nutrients flowing into the Salton Sea, about 100,000 metric tons of algal biomass containing 10% N and 1% P would need to be produced annually, requiting in the order of 1,000 hectares (ha) of algal ponds. The scale of this system suggests that additional algal processes for nutrient removal at the Salton Lake, not requiting fish culture, would also be of interest.

1436 PAS

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Figure 2: Controlled Eutrophication Process (CEP) Flow Diagram. Shown are the high rate ponds ("Algal Growth Channels") receiving Whitewater River inputs containing high nutrient (N and P) levels, followed by the main Tilapia production ponds, in which the algal biomass is converted into fish biomass, fecal pellets and algal flocs, removed in the sedimentation tanks ("High Rate Settling"). (Not shown is the CO2 supplied to the culture). Much of the flow is re-circulated through the high rate ponds with a portion of the treated effluent discharged through a smaller Tilapia culture, followed by slower sedimentation and final polishing of the effluent with chemical coagulants and settling of the flocs. The output is a purified effluent low in nutrients that would be returned to the Whitewater River for discharge into the Salton Sea.

1437 MICROALGAL BIOMASS SYSTEMS FOR FUEL PRODUCTION. As discussed above, extensive R&D has been carried out in the past on microalgae biomass production systems, including conceptual applications to the Salton Sea. Indeed, pioneering work in the 1960's and 70's already anticipated the establishment of large-scale algal ponds at or even in the Salton Sea, for nutrient (nitrate) removal and salinity control, with the algal ponds serving a dual function in salt evaporation and nitrate removal [22]. This early work demonstrated the conceptual rudiments of this approach, including the ability of algal cultures to grow on drainage waters and to remove nitrates. Over the years the Salton Sea featured in several genetic engineering cost analyses [10, 12], including one that developed cost estimates for a pilot-scale facility and full-scale (400 ha) microalgae fuels production plants on the shores of this lake [13]. The latter studies [12, 13] addressed the production of algal oils for conversion to biodiesel. The relatively high cost of oil extraction and biodiesel production makes methane (biogas) generation fi'om algal biomass by anaerobic digestion for on-site power generation a more attractive alternative. An initial cost estimate, based on a recently updated study [23], for a microalgae-biogas production process applied to nutrient removal at the Salton Sea suggests that the total capital investment would be some $40,000/ha. This would be for a 400 ha system with about 50 individual earthen growth ponds of the paddle wheel mixed high-rate pond design. The overall design is essentially a scaled-up version of commercial microalgal production systems, such as the Spirulina producing Earthrise Farms, Inc. plant located near the South shore of the Salton Sea. Major differences would be the use of dilute (appx. 10%) CO2 obtained from the power plant flue gas (rather than the pure CO2 used in Spirulina production), the clay (rather than plastic) lining of the ponds, and the harvesting by spontaneous bioflocculation-sedimentation (rather than with screens), and the use of anaerobic digestion (rather than drying) for the processing of the biomass. Operating costs would be for the power consumed in the process (considered below), for labor and for minor inputs, such as, possibly, flocculating aids, for a total of some $4,000/ha-yr. With annualized capital related charges (taxes, maintenance, insurance, depreciation and cost of capital) at 20% of total investment, this would result in a total cost of $12,000/ha-yr. Assuming an average productivity of 30 g/m2/day and 90% operating capacity, or 100 t/ha-yr (a lower productivity than assumed in other recent studies), total costs would be about $120/t biomass. Net electricity production from the biogas, after deducting parasitic electricity consumption (including an allowance for generation costs), is estimated at 700 to 1,000 kWhr/t of biomass, or a current fuel value of $20 to 50/t of algal biomass. The remainder of the costs of production would be covered from the use of the digester effluents as agricultural fertilizers and the environmental credits for reducing nutrients loadings to the Salton Sea, and for greenhouse gas abatement. Although the $ value per ton of algal biomass of these benefits is not yet well defined, they do appear, in combination, to be exceed the projected biomass production costs. The CEP, through the additional production of fish, would be economically even more advantageous, even considering the additional costs of the fish component. In any event, achieving the goals of low-cost microalgae production requires improvements in algal cultivation processes, increased biomass productivities, low cost harvesting and improved processing. Indeed, the above projected cost of $120/t biomass is far below current costs of commercial algal biomass production, of at least $5,000/t (estimated plant-gate cost for producing dried Spirulina at Earthrise Farms, Inc.). This great disparity between current reality and future projections can be ascribed to several factors: economies of scale (ten-fold larger sizes for growth ponds as well as the overall plant), the greatly simplified process (e.g. no drying, no cost for the nutrients, water or CO2), and three-fold higher productivity (30 g/m2/day) than current commercial Spirulina production. Regarding the latter point, for several reasons, commercial Spirulina culture is of rather low productivity and the projected productivities are well within present experience. Even higher productivities may be achievable through genetic engineering [21, 24], though that research still has to be brought from the laboratory into outdoor pond culture. In summary, microalgae processes for fuel production and greenhouse gas mitigation must be a component of or integrated with other processes, such as nutrient removal from municipal and other wastewaters, fish aquaculture waste treatment (the PAS), a combination of both (e.g. the CEP), and/or processes with large volume co-products, such as fertilizers, chemicals or animal feeds. A potential example of the latter could be the conversion of high-starch algal biomass to ethanol and animal feeds, in analogy with current U.S. corn-to-ethanol production. Such a process could become economically competitive if similar governmental subsidies were available to microalgae as for the corn-ethanol industry. In any event, such multipurpose processes could have relatively short development times, 5 to 10 years (Pedroni et al., These Proceedings].

1438 CONCLUSIONS: MICROALGAE PROCESSES FOR GREENHOUSE GAS ABATEMENT.

Greenhouse gas abatement by microalgae processes is based on the production of renewable fuels replacing fossil fuels and on the other co-products and co-processes derived thereof. A net output of 1,000 kWhr/t of biomass represents 0.8 tons of CO2 abated, based on averaging CO2 emissions of natural gas and coal-fired power plants. The nitrogen contained in the anaerobic digestion residuals would add some 0.3 t of CO/ abated, based on the natural gas used in fertilizer production. In municipal wastewater treatment, microalgae processes would accrue abatement credits from reductions in energy consumption and CH4 and N20 emissions, compared to conventional processes (e.g. activated sludge) [25, 26]. The water resources reclaimed by microalgae waste treatment processes could add to their greenhouse gas abatement credits. Even larger greenhouse gas abatement credits could be projected for the CEP, by comparing the greenhouse gas emissions from conventional animal protein production to that of fish aquaculture systems. Even though the overall value ($/t biomass or S/ha) of greenhouse gas abatement would likely be modest, it could in many instances make the critical contribution to the economic viability of such processes. One difficulty in estimating greenhouse gas reductions is the highly site-specific nature of such systems and a complicating factor is their seasonal variability, a particular challenge in the case of wastewater treatment. These complexities and uncertainties make it difficult to assess the overall potential of microalgae processes to reduce greenhouse gas emissions nationally or globally. Nevertheless, in aggregate, microalgae systems provide many opportunities for greenhouse gas abatement and can make a significant contribution to the global efforts to abate greenhouse gases, in addition to their other environmental and economic functions. REFERENCES.

.

6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. 26.

Oswald, W.J., and Golueke, C.G. (1960). Adv. Appl. Microbiol., 11,223 - 242. Oswald, W.J. (1988). In M. Borowitzka, (ed.). Microalgae Biotechnology, Cambridge U. Press. Oswald, W.J. (1963). Dev. Ind. Microbiol., 4:112-125. Benemann, J.R., Koopman, B.L., Weissman, J.C., Eisenberg, D.M. and Goebel P. (1980). G. Shelef and C.J. Soeder (editors) Algae Biomass: Production and Use, Elsevier, Amsterdam, pp 457-496 Brune, D.E., Collier, J.A., Schwendler, T.E. (2001), U.S. Patent No. 6,192,833, February 27, 2001. Bnme, D. E., Collier, J.A. Schwedler, T.E., and Eversole, G.A. (1999). ASAE.Paper No. 99-5031. Brune, D.E. and Wang, J.-K. (1998). Aquaculture Magazine 24:63 - 71. Wilde, E., and Benemann, J.R., (1993). Biotechnology Advances. 11:781-812. Weissman, J.C., Radway, J.C., Wilde, E., and Benemann, J.R. (1998). Biosources Tech. 65: 87-95. Benemann, J.R., Pursoff, P., Oswald W.J. (1978). Engineering Design and Cost Analysis of a LargeScale Microalgae Biomass System, U.S. Dept. Energy, NTIS #H CP/T1605-01 UC-61. pp. 91. Sheehan, J., Dunahay, T., Benemann, J., and Roessler, P. (1998) A Look Back at the U.S. Department of Energy's Aquatic Species Program -Biodiesel from Algae". NERL/TP-580-24190. Benemann, J.R., Goebel, R.P. Weissman, J.C. Augenstein, D.C. (1982). Microalgae as a Source of Liquid Fuels, Final Report to the U.S. Department of Energy, pp. 202. Weissman, J. C. and Goebel, R.P. (1987). Design and Analysis of Pond Systems for the Purpose of Producing Fuels, Final Report, Solar Energy Res. Inst., Golden CO, SERI/STR-231-2840 (1987). Weissman, J.C. and Tillett, D.T. (1992). In Aquatic Species Project Report, FY 1989-1990, pp.32-56, NREL, Golden Co., NREL/MP-232-4174 (1992). Usui, N., and Ikenouchi, M. (1996). Energy Conserv. Mgmt. 38:$487 - $492. Bayless, D., Brown I.I., Cooksey, B., and Cooksey, K.E. (2002). 1st Cong. Intl. Phyc. Soc. pp. 201. Olaizola, M., Mazzone, E., Thisltehwaite, J., Nakamura, T., and Masutani, S. (2002). Ibid pp. 219. Ikuta, Y., J.C. Weissman, J.C., and Benemann, J.R. (2000). Technology 75:137 - 145. Hase, R., Oikawa, H., Morita, M. and Watanabe, Y. (2000). J. Biosci. & Bioeng. 89:157 -163. Nagase, H., Yoshihara, Hirata, K., and Miyamoto, K. (2001). Biochem. Eng. J., 7:241 - 246. Nakajima, Y., Fujiwara, S., and Tsuzuki, M. (2002). Abstracts, 1st Cong. Intl. Phyc. Soc. pp. 151. Brown, R.L. (1971). Removal of Nitrate by an Algal System. Dept. Water Resources, California Benemann J.R. and Oswald W.J. (1996) Systems and Economic Analysis of Microalgae Ponds for Conversion of C02 to Biomass, Final Report, Pittsburgh Energy Technology Center, pp.260. Polle, J.E., Benemann, J.R., Tanaka, A., and Melis A. (2000). Planta 211:335 -344. Benemann, J.R. (2002). Greenhouse Gas Emissions and Potential for Mitigation from Wastewater Treatment Processes. Report to the Electric Power Research Institute and U.S. Dept. of Energy. Green, F.B., Lunquist T.J., and Oswald, W.J. (1994). Wat. Sci. Tech., 30:9-20 (1994).

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1439

T H E I M P R O V E M E N T OF M I C R O A L G A L P R O D U C T I V I T Y B Y REDUCING LIGHT-HARVESTING PIGMENT - A N A L Y S I S OF A P H Y C O C Y A N I N - D E F I C I E N T M U T A N T OF S Y N E C H O C Y S T I S PCC 6714 Yuji Nakajima l), Shoko Fujiwara2) and Mikio Tsuzuki 2) lAdvanced Technology Research Center, Mitsubishi Heavy Industries, Ltd. 2School of Life Science, Tokyo University of Pharmacy and Life Science

ABSTRACT

We have achieved the improvement of photosynthetic productivity in a continuous culture system at high cell density under high light intensity using a mutant with a small content of light-harvesting pigment of Synechocystis PCC 6714 (PD-1). We analyzed the sequence and the expression of the cpc operon encoding phycocyanin subunits and linker polypeptides in the wild type and PD-1. The sequences of cpc operon were identical in the wild type and PD-1. However, there was a single-base substitution (from T to C) at 5 base upstream of transcriptional initiation site of the cpc operon. The results of northern blot analysis and in vivo transcription activity of the promoter show that the phycocyanin-deficiency ofPD-1 is due to the substitution in the promoter region of cpc operon. We expect that this kind of single-base substitution will contribute to microalgal breeding for mass culture and microalgal products. These results will make a contribution of CO2 biofixation. INTRODUCTION

Microalgae have a high photosynthetic activity on a per unit surface area, so that microalgal mass cultivation has been regarded as useful for CO2 fixation. Furthermore, microalgal mass cultivation can produce algal materials such as industrial materials and food resources, so that many techniques for microalgal mass cultivation have been developed. For the photosynthetic organisms, especially in a commercial mass production, the light energy is essential, because they are mostly cultivated photo-autotrophically. Many devices and much effort have been put into improvement of culture systems using sunlight as to increase algal production. In many cases ofmicroalgal mass production, the algal cell suspension is designed to be so high to absorb the light thoroughly, because the dense microalgal culture minimizes the leakage of received light energy and also helps to reduce the cost of algal harvest. When the culture is conducted at high cell density, however, the photosynthetic productivity can never be increased in proportion to the light intensity under high light intensity, such as sunlight. In many algal species, it is well known that the light-harvesting pigment (LHP) content is changed from high to low when the light intensity is changed from low to high. The LHP content of an alga in the dense cell suspension is high even under high light intensity because of acclimation. Mutual shading in the dense suspension leads the LHP content high even under high light intensity. When the microalgal mass cultivation is conducted under high light intensity and the cells with high LHP content by the acclimation are brought to the irradiated surface by mixing under such a high light intensity, the cells at the irradiated surface can absorb more light energy than that usable for the photosynthetic reactions. The excessive light absorption would cause not only a loss of light energy but also photoinhibition of photosynthesis. The idea of reducing the LHP content is to mitigate the above unfavorable effects caused by

1440 the high LHP content which is inevitably caused by the algal adaptation in a dense culture. The idea was reviewed in detail by Benemann (1989) and was confirmed to be effective using a phycocyanin (PC)-deficient mutant (PD-1) of Synechocystis PCC 6714 (Nakajima and Ueda 1999). The PC is a major LHP in Synechocystis PCC 6714. The PC content on a cell basis was one-third in PD-1 as high as that in the wild type, although the maximum photosynthetic activity as well as the contents of photosystems and chlorophyll (Chl) in PD- 1 was almost the same as in the wild type (Nakajima and Ueda 1997). As we expected, PD- 1 showed 1.5 times higher productivity than the wild types in a continuous culture system at high cell densities under high light intensities. The same results were also with the wild type and the small LHP mutant of Chlamydomonas perigranulata (Nakajima et al. 2001). If the technique of reducing the LHP content is applicable in other strains, the improvement of photosynthetic productivity could be more realistic. Since PD-1 was obtained by nitrosoguanidine mutagenesis, there was no mutation tag. In order to obtain such a mutation tag, we had to start the research for analyzing the mechanism of the PC-deficiency in PD-1. We have considered that the mutation in PD-1 would be attributable to a defect in PC subunits and/or linker polypeptides. The PC-deficiency in PD-1 might be caused by reduction of the rate of biosynthesis or stability of the polypeptides or phycocyanobilin in PC, or the linker polypeptides. In this study, we examined sequence of cpc operon and then found a single-base substitution. Then, we introduced a DNA fragment including the mutation site into a transformable strain, Synechococcus PCC 7942. The results suggest a possibility of improvement of photosynthetic productivity by genetical mutagenesis. BODY OF PAPER

Materials & Methods

Cells and culture conditions The mutant strain, PD-1, of Synechocystis PCC 6714 was kindly supplied by Prof. Fujita of Fukui Prefectual University. The wild type and PD-1 mutant of Synechocystis PCC 6714 were cultured under white light at 25 °C in an MDM medium With a supply of air containing 1% CO2 (Nakajima and Ueda 1997). The culture was conducted in an oblong flask at 50 ~tmol photon m 2 s1. Cells in the late exponential growth phase were used for DNA and RNA extraction. In order to determine the promoter activity of the upstream region of the cpc operon, Synechococcus PCC 7942 was used as a host organism, which was cultured under white light at 30 °C in BG11 medium with a supply of air containing 3% CO2. The culture was also conducted in an oblong flask at 50 ~tmol photons m 2 s". The cells in the exponential growth phase were harvested and used for transformation.

Isolation of DNA and RNAfrom Synechocystis PCC 6714 Genomic DNA of Synechocystis PCC 6714, as a template for the PCR reaction, was isolated using a GNOME kit (Qbiogene, Carlsbad, CA, U.S.A.) or a GenomicPrepa~ (Amersham Pharmacia Biotech, Buckinghamshire, England) according to the supplier's manual. Total RNA was prepared by the hot-phenol extraction method as follows. Cells were harvested and then suspended in 3mL of 20 mM sodium acetate containing 0.5% SDS and lmM EDTA. An equal volume of buffered phenol was added to the cell suspension. After the incubated for 10 min at 60 °C, the suspension was centrifuged for obtaining the aqueous phase. The aqueous phase was treated with chloroform, and was precipitated by ethanol. The precipitate was purified by the CsC1 ultracentrifugation method.

Northern blot analysis Equal amounts of total RNA were separated by electrophoresis in formaldehyde-containing gels and then transferred to nylon membranes. The RNA separated by electrophoresis fixed on the membranes was hybridized with radio!abeled nucleic acid probes for the cpcA, cpcB, cpcC1, cpcC2, cpcD, cpcE, cpcF, cpcG1, cpcG2, apcA andpsbAI genes. These probes were prepared by means of the PCR reaction with reference to the sequence of Synechocystis PCC 6803 (Kaneko et al. 1996).

1441

Transformation ofSynechococcus PCC 7942for the promoter assay A plasmid, pAM1414 (Andersson et al. 2000), which was kindly provided by Prof. S. S. Golden of Texas A&M University, was used as a vector for the construction of promoter-reporter fusions. This plasmid carries the promoterless luxAB gene of Vibrio harveyi, two parts of the neutral site I (NSI) of Synechococcus PCC 7942, a spectinomycin-resistant gene and pBR322 replicon. The DNA fragments (763 bp, -767 - -4) of the upstream region of cpcB amplified using the wild type and PD-1 DNA were ligated into NotI / BamHIdigested pAM1414 to construct pANY 1 and pANY2, respectively (Figure 1). The Synechococcus PCC 7942 wild strain was transformed with pANY1 or pANY2, which yielded spectinomycin-resistant colonies. These transformants carried the upstream region of cpcB were the luxAB fusion at the neutral site I (NSI) of the chromosome, as a result of homologous recombination.

~

Upstream region on the cpc operon

Synechococcous PCC 9742 NS1

NS1 ~SpR Transformant ~mt Ii!!::i;::i~ Figurel: Construction of plasmids for the promoter assay. The upstream region of the cpc operon of the wild type (for pANY1) and PD-1 (for pANY2) was ligated into the cloning sites, NotI and BamHI, of pAM 1414. The plasmids have a segment of DNA from the Synechococcus PCC 7942 chromosome (NSI) that mediates homologous recombination with the chromosome.

Assaying of Bioluminescence The bioluminescence of the cell suspension was determined with a luminometer (Lumat LB9501, Germany) immediately after the addition of n-decanal. The intensity of the bioluminescence was expressed in RLU per minute per micromole of Chl. Chl was repeatedly extracted with hot acetone (80% v/v), and its content was calculated using the coefficients. RESULTS & DISCUSSION

Analysis ofcpc operon in Synechocystis PCC 6714 To clarify the mutation site in PD-1, we determined the complete sequence of the cpc genes in the wild type and PD-1 by direct sequencing of PCR products (from 822 bp upstream of the translational start codon of cpcB to 280 bp downstream from the stop codon of cpcD). The primer pair in order to obtain the DNA fragment was designed with reference to the sequence of Synechocystis PCC 6803 (Kaneko et al. 1996), which is related species of Synechocystis PCC 6714. The sequence revealed that 259 bp upstream of the predicted initiation codon of the cpcB was T in the wild type, while it was replaced by C in PD-1 (Figure 2). The recent experiment revealed that this substitution had been occurred at 5 base upstream of transcriptional initiation site of the cpcB (Imashimizu et al. Unpublished data). No other difference was observed in the upstream region of cpcB. The expression of cpc genes in both cell types was investigated. The pattern on Northern blot analysis of both types and the complete sequence of cpc operon suggested that cpcA, cpcB, cpcC1, cpcC2 and cpcD constitute an operon, in the order (Figure 3, data not shown for cpcA, cpcC1 and cpcC2). The results of

1442 Northern analysis ofPD-1 demonstrated that the levels of the cpcB, cpcA, cpcC1, cpcC2 and cpcD transcripts were one-tenth to one-sixth as high as those in the wild type (Figure3, data not shown for cpcA, cpcC1 and cpcC2). However, the mRNA levels ofpsbA1 and other phycobilisome genes were almost the same in the two cell types (Figure 3, data not shown for cpcA, cpcC1, cpcC2,, cpcE, cpcF, cpcG1 and cpcG2,). These results indicate that the PC-deficient mutation in PD-1 is due to reduction in the transcription of the cpc operon. -I0 region -300

AAGACGTAACAGACAGAAGTTGCACCAGCATT~TATAAAIGT T A A C ~ IGTGG

-250 -200 -150 -i00 -50 1

GATTGCAAAAGCATTCAAGCCTAGGCATTGAGCTGTTTGAGCGTCCCGTT GGCCCTGTGTCTGTGTCTGTAACTTTCCCTTGGGTTGAGCTGGATAACGC CTCTCATAAATTCCCTTGGTAACCAAAGAAAGTTTTATGGAGAGCAGCCA 'TAATCATTCCGGGGTCACTGCTTTGGACTCCCTCACTTAATACGAGGGAA TTGTGTTTAAGAAAATCCCAACTCATAAAGTCAAGTAGGAGATTAATTCA ~TGTTCGACGTATTCACTCGGGTT >

C

cpc B Figure 2: Nucleotide sequence of the upstream region of the cpc operon. This nucleotide sequence is presented from the translational start codon of cpcB to 300 bp upstream of cpcB. In PD-1, T is substituted for C at 5 bp upstream of the transcriptional initiation site (+1) of the cpcB, which was confirmed by primer extension. Rest part of sequences are identical in the two cell types.

nsbAl

ancA

cncB

cncD

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I

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1.E-04

1.E-03

Current density (A/cm2) (a)

I .E-02

Current density (A/cm2) ~

Oxalic acid ---0--. Hydrochloric acid (b)

Figure 4: Cyclic polarization curve of (a) oxalic acid for CS 1018 and (b) oxalic acid and hydrochloric acid for SS.316.

CONCLUSIONS For the CO2-1oaded aqueous solution of MEA, all test heat stable salts, including acetate, chloride, formate, glycolate, malonate, oxalate, succinate and sulfate, aggravated corrosion of carbon steel. Oxalate was the major contributor to an increased corrosion rate. None of the test heat stable salts showed pitting tendency on both carbon steel and stainless steel.

ACKNOWLEDGEMENTS Financial support from the Natural Sciences and Engineering Research Council o f Canada (NSERC) and Imperial Oil is gratefully acknowledged.

REFERENCES 1. 2. 3.

Nielsen, R.B. and Lewis, K.R. (1995) Corrosion in refinery amine systems: NACE International Corrosion'95: paper no. 571. Rooney, P.C., DuPart, M.S. and Bacon, T.R. (1997) Hydrocarbon Processing 76 (4), 65. Keller, A.E., Kammiller, R.M., Veatch, F.C., Cummings, A.L. Thompsen, J.C. and Mecum, S.M. (1992) Heat-stable salt removal from amines by the HSSXprocess using ion exchange: Laurance Reid Gas Cond. Conf. 73, 61.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1595

CORROSION IN CO2 CAPTURE UNIT FOR COAL-FIRED POWER PLANT FLUE GAS A. Veawab Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada $4S 0A2

ABSTRACT This paper reviews the knowledge of corrosion and corrosion control in the CO2 capture unit using reactive amine solvents. Plant experiences and the impacts of operating parameters on corrosion in the amine unit are addressed. The key operating parameters are amine type, amine concentration, solution temperature, CO2 loading, solution velocity, and degradation products. The corrosion data obtained from our laboratory experiments as well as from the literature over the decades were integrated to establish the interrelationship between such operating parameters and corrosion rate. This paper also reviews all the corrosion mechanisms that are commonly used to characterize corrosion phenomena in this particular CO2-amine system as well as the one that was identified by our rigorous corrosion model. In addition, the information on corrosion control and our work on low-toxic corrosion inhibitors are also provided.

INTRODUCTION Carbon dioxide (CO2) capture unit using reactive amine solvents is constantly subject to excessive corrosion problem. Based on plant experiences, corrosion takes place in almost every section of the plants. The most susceptible areas include the bottom portion of the absorber, flash drum, rich-lean heat exchanger, regenerator and reboiler. The corrosion detected in these areas occurs in many forms, i.e. uniform, pitting, erosion, galvanic, stress corrosion cracking and inter-granular. The corrosion problem has a direct impact on the plant's economy as it can result in unplanned downtime, production losses, reduced equipment life. It can also affect the plant's economy in an indirect way by limitingthe operational ranges of process parameters, such as amine concentration. As such, the capture unit cannot be practically operated to increase the unit throughput and/or to reduce the process cost, especially the operating cost due to excessive energy consumption in the regeneration section. Due to the tremendous corrosion impacts, suppression of excessive corrosion to an acceptable level becomes necessary for amine treating plants. In general, corrosion can be reduced by a number of approaches including i) use of proper equipment design, ii) use of corrosion resistant materials instead of carbon steel, iii) removal of solid contaminants from liquid solution, and iv) use of corrosion inhibitors. Of these alternatives, the use of corrosion inhibitors is considered to be the most economical technique for corrosion control.

I M P O R T A N T O P E R A T I N G PARAMETERS Corrosion in amine treating plants is influenced by a number of factors including CO2 loading, amine type, amine concentration, temperature, solution velocity and degradation products. CO2 loading or CO2 content in the amine solution is considered to be the primary contributor. An increase in CO2 loading intensifies the

1596 system's aggressiveness, thus accelerating the corrosion process [1, 2] (Figure l-a). As a result, the rich amine solution is generally more corrosive than the lean amine. There are a number of references providing guidelines for the CO2 loading that limits corrosion to the acceptable levels [3]. The recommended maximum CO2 loadings in the rich amine solution are in the range of 0.25-0.40 mol/mol, 0.33-1.00 mol/mol, 0.45-0.50 mol/mol, 0.25-0.45 mol/mol and 0.50-0.85 mol/mol for MEA, DEA, MDEA, DGA and DIPA, respectively. Temperature has a significant impact on corrosion as higher temperature tends to increase the rate of corrosion [2, 4, 5, 6] (Figure l-b). Because the operating temperature of the absorption process varies from 40°C to as high as 120°C, a great diversity of corrosion rates can be found throughout the plants. The most susceptible process areas are the rich-lean heat exchanger, the regenerator and the reboiler where the amine solutions are heated to an elevated temperature. For regions such as the absorber and the amine cooler, the operating temperature is relatively low and corrosion damage is rather small. 70 •--o- MEA-3.2M-121C (Kuznetsov et al., 1999) --o- MEA-3.2M-135C (Kuznetsov et at., 1999)

A 6O

// 50 --k- MEA-3.2M-149C(Kuznetsovet ai., 1999) / / -x-AMP-2.0M-80C (Veawab et al., 1999)

/

- e - MEA-2.0M-80C (Veawab et al., 1999)

/

p

4O

40

i+

30

20

10

~ 2o u

50

lo

100

150

200

T e m p e r a t u r e (°C)

0

0.1

0.2

0.3

0.4

C02 loading (mollmol)

(a)

0.5

0.6

0.7

MEA-49M (DuPart et al, 1991 ) DEA-1 9M (OuPart et al., 1991 ) MEA-3.2M (Helle, 1995) -->(--- DEA-2.0M (Helle, 1995) ---m---MDEA-4.2M (Keller et al., 1992) MEA-2.0M (Veawab et al, 199) -.o-- DEA-2 0M (Veawab et al, 199) AMP-2.0M (Veawab et al., 199)

(b)

Figure 1: Effect of CO2 loading and temperature on corrosion Amine type plays an essential role in corrosion. Although pure amines are not corrosive to carbon steel regardless of temperature, the amine aqueous solutions containing only small amounts of CO2 can be quite corrosive. Different types of amines induce different degrees of system corrosiveness. Generally, the primary amine (MEA) is found to be more corrosive than the secondary amine (DEA) which is in turn more corrosive than the tertiary amine (MDEA) [2] (Figure 2-a). The reason for this behavior is not fully understood. However, it was suggested that the Lewis base strength of the individual amine was responsible for the rate of corrosion [7]. Concentration of amine solution also affects corrosivity, i.e. an increase in amine concentration causes the higher corrosion rate [2, 4, 8] (Figure 2-b). Generally, use of a high amine concentration is desirable for energy saving purposes. However, too high amine concentration can damage the plants to a great extent. To limit the plant corrosion within the acceptable and manageable level, most of the amine plants are operated in compliance with the recommended maximum amine concentrations. These concentrations are in the range of 10-20 wt%, 20-40 wt%, 50-55 wt%, 50-65 wt% and 20-40 wt% for MEA, DEA, MDEA, DGA and DIPA, respectively [3]. Solution velocity can cause severe erosion corrosion, especially in the presence of solid contaminants. In a system without a protective film, the corrosion rate is completely controlled by solution velocity [9]. With inhibited systems, a protective film is normally developed to cover the metal surface and suppress the

1597 excessive corrosion. However, this film can be removed or damaged by the shear force of a high velocity fluid stream. As a result, erosion corrosion will be introduced into the system.

lso.J

)

80

E lO0-r ---)

)

g o .,-

g,

8

20

50-~

m 0

..,IN-

1

AMP

2

3

4

5

6

A m i n e concentration (M)

o.A~N

DEA

MEA

--O--DEA-100C (Chakma and Meisen, 1986) •--.&-- MEA-99C (DuPart et al., 1991) --e--DEA-99C (DuPart et al., 1991) ~ M D E A - 9 9 C (DuPart et al., 1991) .-e,-- MEA-80C (Veawab et al., 1999) --e--AMP-80C (Veawab et al., 1999) --4:3-- DEA-80C (Veawab et ai., 1999)

MDEA

3 kmol/m a, 80°C

(b)

(a)

Figure 2: Effects of amine type under CO2 saturation condition and amine concentration. Amine degradation is a chemical process that causes a reduction in the amount of reactive amine participating in the CO2 absorption process. Aqueous amine solutions can be degraded in the presence of carbon dioxide and oxygen. As reported by Gregory and Scharman [10], solvent degradation leads to corrosion in MEA plants. For plants using other amines, such as DEA, the connection between corrosion and degradation however remains inconclusive. Blanc et al. [11 ] stated that the DEA degradation had no or very little effect on carbon steel corrosion but other researchers showed there was a connection between the two operational problems [5,12,13].

CORROSION MECHANISMS Corrosion mechanism in an aqueous amine-CO2 system is not well understood. Several mechanisms have been used to postulate the corrosion phenomena. Riesenfeld and Blohm [14] suggested that the corrosion was associated with an evolution of CO2 from the rich amine solution. The evolved CO2 then reacts directly with carbon steel to form iron carbonate (FeCO3). However, in most cases, mechanisms of iron dissolution in a CO2-water system are used to represent the corrosion mechanism in the aqueous amine-CO2 system. Three different types of iron dissolution reactions have been suggested. First, the dissolution reaction involves a reduction of hydrogen ion (H +) (Eqn. 1). Second, bicarbonate ion (HCO3) in the solution functions as an oxidizing agent in the reduction reaction (Eqn. 2). Third, the reaction is governed by undissociated carbonic acid (H2CO3) (Eqn. 3). Fe + 2H + ~

f e 2+ + 9 2

(1)

Fe + 2HC03-

--9 FeC03 + C032 -k 9 2

(2)

Fe + H2C03

~

(3)

FeC03 + 11:

Recently, a mechanistic corrosion model was established to identify the oxidizing agents responsible for corrosion reactions in an aqueous amine-CO2 system [ 15]. The model incorporated the rigorous electrolyte-

1598 NRTL equilibrium model and mixed potential theory in order to simulate the concentrations of chemical species and the polarization behavior taking place at a metal-solution interface. The simulation results, based on the MEA system, indicated that HCO3- and H20 are the primary oxidizing agents and H+ plays an insignificant role in the reduction reaction.

CORROSION INHIBITORS

For decades, various corrosion inhibitors have been developed, commercialized and patented by many major chemical companies for uses in the amine treating plants. Inorganic corrosion inhibitors are in practice more favored than the organic compounds because of their superior inhibition performance. Among these, vanadium compounds, particularly sodium metavanadate (NaVO3), are the most extensively and successfully used in the amine treating plants. However, there is a concern over the use of toxic inorganic inhibitors as it makes disposal of the resulting industrial waste difficult and costly. This fact, together with growing environmental concern, has made the shifting from toxic corrosion inhibitors to the ones with less toxicity a significant corrosion issue in the field of gas treating [16]. The possibility of using low-toxic corrosion inhibitors instead of heavy-metal inhibitors, for CO2 absorption systems was investigated by Veawab et al. [17]. The performance of eight low-toxic organic inhibitors (amines, carboxylic acid and sulfoxide) were evaluated by conducting electrochemical corrosion experiments with carbon steel-1020 specimens immersed in 3.0 k m o l / m 3 MEA solutions under CO2 saturation. The experimental results showed that carboxylic acid had the best inhibition performance (as high as 92%), followed by sulfoxide and longchain aliphatic amine. Their performance depended upon inhibitor concentration and temperature.

ACKNOWLEDGEMENT

Natural Sciences and Engineering Research Council of Canada (NSERC) is gratefully acknowledged for financial support and experimental equipment.

REFERENCES

1. 2. 3. 4.

Kuznetsov, Y.I., Andreev, N. N. and Ibatullin, K.A. (1999) Prot. Met. 35(6), 532-536. Veawab, A., Tontiwachwuthikul, P. and Chakma, A. (1999) Ind.& Eng. Chem. Res. 38(10), 3917-3924. Nielsen, R.B., Lewis, K.R. and McCullough, J.G. (1995) Corrosion 95. DuPart, M.S., Bacon, T.R. and Edwards, D.J. (1991) Proc. Laurance Reid Gas Cond. Conf. 41 st, 196227. 5. Helle, H.P.E. (1995) Corrosion 95, paper no. 574. 6. Keller, A.E., Kammiller, R.M., Veatch, F.C., Cummings, A.L., Thompsen, J.C. and Mecum, S.M. (1992) Proc. Laurance Reid Gas Cond. Conf. 42 nd, 61-92. 7. Teevens, P. J. (1990) Corrosion 90, paper no.384. 8. Chakma, A. and Meisen, A. (1986) Ind. Eng. Chem. Prod. Res. Dev. 25(12), 627-30. 9. Videm, K.and Dugstad, A. (1989) Materials Performance 28(3), 63-67. 10. Gregory, L. E. and Scharman, W. G. (1937) 1BID 29, 514. 11. Blanc, C., Grail, M. and Demarais, G. (1982) Proceedings of Gas Conditioning Conference. 12. Polderman, L. D. and Steele, A. B. (1956) Oil and Gas Journal 54(65)i 206-214. 13. Moore, K. L. (1960) Corrosion 16(10), 111-114. 14. Riesenfeld, F. C. and Bholm, C. L. (1950) Pet. Ref 29(4), 141-150. 15. Veawab, A. and Aroonwilas, A. (2002) Corrosion Science 44, 967-987. 16. Asperger, R.G. (1994) Proc., Annu. Conv. - Gas Process. Assoc. 73 rd, 189-92. 17. Veawab, A., Tontiwachwuthikul, P. and Chakma, A. (2001)lnd.& Eng. Chem. Res., 40(22), 4771-4777.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1599

N E W AMINES FOR THE REVERSIBLE A B S O R P T I O N OF C A R B O N DIOXIDE F R O M GAS M I X T U R E S Michele Aresta and Angela Dibenedetto* Department of Chemistry and METEA Research Center, University of Bail, Via Celso Ulpiani, 27, 70126 B a r i - Italy Phone +39 080 544 2078, Fax +39 080 5442083 E-mail: [email protected]

ABSTRACT In this paper we discuss the use of new amines as a medium for the capture of CO2 from a gas mixture. The study was carried out comparing the absorption of carbon dioxide by two alkyl-di-amines with that of amines used so far at industrial level, namely mono-ethanolamine (MEA). A known mono silyl-alkyl-amine was also studied for comparison. The absorption of carbon dioxide was studied at different temperatures, in water solution, in organic solvents and using the neat amine. Several cycles of absorption/desorption were carded out. Xerogel solidified amines were also used.

INTRODUCTION Anthropogenic carbon dioxide is considered to be the greenhouse gas which most contributes to global warming. Its concentration in the atmosphere is considerably increased and the control of CO2 immission has been agreed at the international level. The capture of carbon dioxide from flue gases may be used as a mitigation technology. Several technologies have been developed for separating carbon dioxide: absorption by liquid amines [1,2] or solid materials, [3] or membrane separation [4,5]. Several examples of carbon dioxide absorption using liquid amines have been reported in the literature and, recently, also the use of ionic liquids beating primary amines [6] has been described. Mono-ethanolamine (MEA) and methyl-diethanolamine (MDEA) are the most popular amines used, either separately or combined at different ratios [7,8]. A separation technology can be exploited at industrial level if it is reliable and cheap. CO2 separation by amines is more economically convenient than the use of membranes. Therefore, the amount of CO2 absorbed per unit of absorbent is a key factor. Consequently, finding new amines able to capture a higher amount of carbon dioxide per mol has a great economic interest [9]. RESULTS It has been long known that aliphatic amines react with CO2 (Eqn. 1a) to afford an ammonium carbamate that, with some amines, may be converted into dimeric carbamic acid (Eqn. 1b) [ 10, 12]. 2 RNH 2 + CO2

--9.

RNH3+-O2CNHR

(1 a)

1600 RNHCOO-+H3NR

+ CO2

~

(lb)

(RNHCOOH)2

While, to date, the reaction of several mono-amines with CO2 has been studied, di-amines have not been investigated. We have studied the up-take of CO2 by using four alkyl mono- and di-amines, namely H2N(CH2)3Si(OMe)3 (I), HzN(CHz)3Si(OEt)3 (II), HzN(CH2)2NH(CH2)3Si(OMe)3 (III) and CH3(CHE)ENH(CH2)2NH2(IV) at different temperatures, in solution and as a pure sample. Figure 1 shows that amine I and II react within 15 min with C 0 2 at 298 K in THF. The amount of C 0 2 absorbed is almost 0.55 mol/mol of amine and this is in accordance with the stoichiometry of reaction l a, where one mol of CO2 reacts with two mol of amine to afford the relevant ammonium carbamate. This behavior is the same observed for MEA (Fig. 1).

| 0,9

l 0,9 .~ 0,8 0,7 ~. 0,6 ~ 0,5 0,4

~

~

~ o,3

-- -@--- monoan~ne !(298_K! - - ~ -- monoamine II (298 K) - - ? - -MEA(298 K) monoamine II (273 K)

~! ~'

~ 0,2 0,1 0 0

4

s4m

8

12 16 20 24 28 32 36 Time (rain)

Figure 1" Kinetics of reaction of silyl-alkyl mono-amines with carbon dioxide

..-

0,8 h" 0,7 ~.0"" ~d 0,6 0,5 ~"0,4 ~d 0,3 ~ 0,2 ,~

- - 41, - -di-aminelV -- • -- MEA

0,10 / 0

Jt 15

30

45

60

di-amine III 75

90

105

Time (rain)

Figure 2" Kinetics of reaction of di-amines with carbon dioxide

For both amines I and II, after the up-take of carbon dioxide it is possible to isolate a white solid which shows the characteristic IR band (1535 cm 1) of the ammonium carbamates obtained from other aliphatic mono-amines. Moreover, we have found that if the reaction is carried out at 273 K, the absorption curve of CO2 has a different shape with time. In fact, the absorption slowly increases to 1 mol of CO2 per mol of amine within less than 1 h (Fig. 1). This different behavior can be explained considering that, as already reported [ 10, 11 ], the ammonium carbamate may slowly convert into the dimeric form of the carbamic acid (Eqn. lb). In previous work [ 10], where C6HsCH2NH2 and CoCI(NO)2[PhP(OCH2CH2)2NH] were used, the dimeric carbamic acid was isolated and characterized by XRD. In the present work, by using amine I and II it was not possible to isolate the acid as a solid, but aider evaporation under vacuo of the solvent, a sticky liquid difficult to handle was obtained. The absorption of carbon dioxide by using mono-amines I and II was not reversible. No release of carbon dioxide was observed heating under vacuo at 330 K [12], while at higher temperatures the ammonium carbamate easily decomposed. Figure 2 shows the C O 2 uptake curve of di-amines III and IV at 295 K. Differently from the mono-amines, (Fig. 1) one mol of CO2 per mol of amine was taken up by amine III. In previous work [12], we have shown that amine III affords an intra-molecular more than an inter-moleCular carbamate. The reaction was quite fast (less than 20 minutes) and a glassy material difficult to handle was isolated. Nevertheless, by evaporating the amine solution under CO2 atmosphere, directly on a single KBr disk, it was possible to record the IR spectrum which shows the characteristic band at 1540 cm -I due to the carbamate RHNCOO- moiety [12]. The reaction quickly takes place also in absence of solvent, assuming that a thin film of the amine is used. As shown in Fig. 2, di-amine IV also takes-up CO2 with a 1:1 molar ratio, but differently from amine III, affording a white light powder more easy to handle. In both cases, the absorption was reversible and carbon dioxide was completely released at 333 K. If neat amine was used, the starting material was quantitatively recovered. Di-amines are, thus, able to absorb the

1601 double amount of CO2 per mol than mono-amines. A water solution of amine IV (H20:amine=1:1) was also used as absorbent mixture. By heating to 333 K CO2 was released: only half o f the CO/ absorbed was evolved. Such amount was then absorbed and desorbed for several cycles (Fig. 3). When a gas mixture (86% N2/14% CO2 ) was contacted for two minutes with the stoichiometric amount (with respect to CO2) of the amine, by monitoring the gas phase by GC we observed the complete disappearance of the CO2 signal (Fig. 4).

0.6 • . ~ . . . = . . . ~ . . . ~ . . . ~ .

~

0.5

1

,

,..~

i

,

,

i

i

,

,

i

, i

.

.

.

. ~ . . . |

.

.

.

i

,

.

.

i

" t

._= 0.4 E

(b)

0.3

(a)

O 0.2

_'~= 5.216 CO2 0.1

0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 Time (min)

Figure 4: GC of the mixture of gases before (a) and (b) after the absorption (time of contact: 2 min).

Figure 3: Absorption/desorption cycles of a water solution of di-amine IV.

When a N2/CO2 gas mixture (CO2=14.4%) and a water solution of amine IV (H20:Amine=55:l) were contacted, the same behaviour was observed (Figure 5). As shown in Fig. 5, the first absorption almost reached the 1:1 molar ratio. When the system was heated to 333 K, only half amount of CO2 absorbed was released. A second cycle was run. If fresh amine was added to the system (Cycle 3, Fig. 5) an increase of absorption of CO2 was observed due to the addition of the amine, but again when the system was heated to 333 K the amount of CO2 released did not correspond to the total amount absorbed. 1,4

addition of flesh amine

1,2

1,2045

._. 1 E E ,t E

0,8 ~

~

0,6815

0,6 0,4

E

Cycle 1

0,2

0

100

200

!,3285 Cycle 21~

300

400

0,32075Cycle 3

500

600

700

Time ( m i n )

Figure 5:CO2 absorption/desorption cycles using a water solution of di-amine IV and a N2/CO2 gas mixture The use of water or organic solvent solutions poses some limitations for the working temperature essentially for avoiding loss of amine by evaporation during the desorption phase that occurs with heating.

1602 It is very attractive to find an absorption/desorption system that does not decompose at high temperature (e.g. at the temperature of flue gases from a chimney: this would allow recovery of CO: without cooling the gas. From this point of view inorganic membranes are very attractive. We have tried to support amine III on a sol-gel matrix and to check its behaviour when the gel was contacted with a gas mixture. The silica xerogel was obtained by condensation of amine III and silicon alkoxydes under hydrolytic conditions. The homogeneous transparent gel obtained was then dried to obtain a white powder, which was contacted with the mixture of gases. Figure 6 shows the absorption/desorption cycle for a xerogel contacted with a gas mixture containing CO2. Several cycles were run in a closed loop. The absorption/desorption was very fast and reproducible.

25 =

•

20

,X . . . . .

e

E ,,,

15

0 rd

10

X 5

absorption

- - -X- - - d e s o r p t i o n

0

20

40

60

80

100 120 140 160

Time (rain) F i g u r e 6: Absorption/desorption of CO2 from a N2/CO2 gas mixture by using xerogel

The limiting factor of this system is the temperature used for drying the xerogel. In fact, the xerogel was able to take up carbon dioxide only if it was dried under vacuum at room temperature. Conversely, if it was dried by heating to 323 K, the xerogel did not absorb CO2. It is worth noting that at 323 K, the gel becomes opaque and the colour changes form white to yellow. The presence of the amine in the xerogel is crucial for cyclic up-take/release of CO2. In fact, if only Si(OR)4 was hydrolysed, the resulting material was not able to absorb cyclically CO2. ACKNOLEDGEMENTS This work was supported by the CNR Grant Agenzia 2000, Contract CNRC008BF and Ministry of University, Contract MM03027791. The authors thank Ms. Roberta Girardi for experimental assistance. REFERENCES 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12.

Bishnoi,S., Rochelle, G. T. (2000), Chem. Eng. Sci., 55, 5531. Rangwala,H.A. (1986)J. Membr. Sci., 112, 229. Byota, D. A. (1974) US Patent 3 847 837 Bhide, B.D., Stem, S.A. (1993) J. Membr. Sci., 81,209. RUCADI Project, BRRT-CT98-5089, (2002), final report. Bates, E. D., Mayton, R. D., Ntai, I., Davis, J. H. (2002) J. Am. Chem. Soc. Chem. Commun., 124, 926. Chakravarty, T., Phukan, U.K, Weiland, R.H. (1985) Chem. Eng. Prog., 81, 32. Glasscock,D.A., Critchfield, J.E., Rochelle, G.T. (1991) Chem. Eng. Sci., 46, 2829. Dibenedetto,A., Aresta, M., Narracci, M. 223rdACS National Meeting, April 7-11, 2002, Orlando Florida. Aresta, M., Ballivet-Tkatchenko, D., Belli Dell'Amico, D., Bonnet, M.C., Boschi, D., Calderazzo, F., Faure, R., Labella, L., Marchetti, F. (2000) Chem. Commun. 13, 1099. Aresta, M., Ballivet-Tkatchenko, D., Bonnet, M.C., Faure, R., Loiseleur, H. (1985) J. Am. Chem. Soc. 107, 2994. Dibenedetto,A., Aresta, M., Narracci, M., Fragale, C. (2002) Green Chemistry in press

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1603

CARBON DIOXIDE ABSORPTION WITH AQUEOUS POTASSIUM CARBONATE PROMOTED BY PIPERAZINE J. Tim Cullinane and Gary T. Rochelle Department of Chemical Engineering, The University of Texas at Austin Austin, Texas 78752, USA

ABSTRACT This paper presents thermodynamic and kinetic data collected for aqueous blends of piperazine (PZ) and potassium carbonate (K2CO3). Mixtures of K + and PZ have been investigated in a wetted-wall column at 40 to 80°C, typical conditions for an industrial absorber. The addition of 0.6 m PZ to 20 wt% (3.6 m) K2CO3 increases the rate of CO2 absorption by a factor of ten from the value in unpromoted solutions at 60°C. The addition of PZ increases the heat of absorption from 4 kcal/mol in 3.6 m K + to 10 kcal/mol when 0.6 m PZ is added. The capacity, ranging from 0.4 to 0.7 molCO2/kg-H20, approaches that of monoethanolamine (MEA) solutions and seems to be a strong function of K ÷ concentration. Speciation of the solution was obtained using proton nuclear magnetic reasonance (NMR), verifying and quantifying the presence of three PZ species. An equilibrium model and a rate model were developed to predict system speciation, equilibrium, and CO2 absorption rate. The model predicts that 3.6 m K + increases the specific rate constant of PZ by a factor of five from its value in water.

INTRODUCTION Amine and potassium carbonate solvents have proven useful for the removal of CO2 from natural gas and H2. Researchers have shown that blending amines accelerates the absorption process [ 1,2,3]. Others have investigated amine/K2CO3 blends with some success [4,5]. This work focuses on promoting K2CO3with PZ, a cyclic diamine. Previous research indicates that PZ is an effective promoter in methyldiethanolamine (MDEA) and monoethanolamine solutions [2,3]. Piperazine is expected to accelerate absorption rates while K2CO3 retains a low heat of absorption. Also, the reaction of carbonate in bulk solution is expected to improve solvent capacity.

METHODS AND RESULTS

Speciation Proton and carbon-13 NMR were used to determine the distribution of piperazine (PZ), piperazine carbamate (PZCOO-), and piperazine dicarbamate (PZ(COO-)2) at equilibrium as a function of CO2

1604 loading (Figure 1). Piperazine carbamate and PZ(COO-)2 do not exist at low loading. As loading increases, the relative amount of PZCOO- goes through a maximum and PZ(COO-)2 becomes an important species. Even at a high CO2 loading, P Z C O O remains a significant portion of the piperazine species. Temperature, from 25 to 60°C, was found to have a minimal effect on the speciation; however, free PZ concentrations generally increase as temperature increases. 100

¢1 (D o,= O

|

~

,

0 ! -0.4

~

i

!

,

!

i

i

i_~

,

i

!

!

,

i

i

i

i

!

,

|

,

i

i

i

i

i

|

,

|

i

i

i

i

i

!

,

,

i

,

,

,

i

,

|

,

,

,

8O

Q.

¢n

60

C ==,.= N i,,= ..== Q.

40

O

20

-0.3

,~

-0.2

-0.1

0.0

0.1

I

0.2

~

0.3

Loading (mol CO=/(mol PZ + mol K22*) - 1)

Figure 1: PZ Speciation in 3.6 m K+/0.6 m PZ, 60°C, Points: NMR Data, Lines: Model Predictions

Equilibrium and Absorption Rates The rate of C02 absorption and solubility of CO2 were determined by contacting a N2:CO2 gas mixture with the solvent in a wetted-wall column [6]. The rate was interpreted as normalized flux, kg', which can be defined as

-

Nc°:

k,'-Pco;, _Pco; =

4Dc°: {kAm[AmICOz]}

(1)

Hco,

Figure 2 summarizes the normalized flux of CO2 absorption as measured. Adding 0.6 m PZ to 3.6 m K + increases the rate of CO2 absorption by a factor of ten at 60°C. The rate of this solvent approaches that of 5 M MEA at both 40 and 60°C. At a rich loading, 3.6 m K+/0.6 m PZ solutions also compare favorably to MDEA/PZ blends [2] and DEA- and hindered amine-promoted systems [4]. The potassium concentration was shown to have little affect on the absorption rate [7]. At a constant CO2 vapor pressure, increasing the temperature from 40 to 80°C increases the normalized flux by a factor of two [7]. The heat of absorption of CO2, AHabs, was estimated from the temperature dependence of the CO2 solubility. The addition of 0.6 m PZ to 3.6 m K + increases AHabs from 3.7 [8] to 10.5 kcal/mol. A decrease in loading at an equivalent concentration increases AHabs from 10.5 to 14.0 kcal/mol, most likely due to differences in the heats of absorption of PZ and PZCOO. With a comparable loading and PZ concentration, a 4.8 m K ÷ solution has a slightly decreased AHabs of 10.2 kcal/mol.

1605 The solvent capacity of PZ/K2CO3 solutions varies significantly with concentration. Over a partial pressure range of 330 to 3300 Pa at 60°C, a 3.6 m K + solution has a capacity of approximately 0.4 m. The addition of 0.6 m PZ to 3.6 m K + at similar conditions increases the capacity to 0.5 m. An increase in potassium concentration to 6.2 m increases the solvent capacity to 0.73. The capacities of solutions containing large amounts of K + compare favorably to amine solvents such as 5.0 M MEA (0.81 m) and 0.6 M PZ/4.0 M MDEA (0.78 m) [2].

,

,

,

,

, ,

,1

,

,

,

,

,

, ,

,|

..... A

(Dang, 2001)

i

oE le-10

3.6 m K*/0.6 rn P Z ~ ~ . ~ . . ~

-./.-..

0

E X

6.2 rn K*I1.2 rn PZ t~, \

4.8 rn K*I0.6 m P2

N

° . . ,=,.

E o z

3.6 m K*/0.0 m PZ le-11

100

1000

10000

PC O z* (Pa) Figure 2" Normalized Flux of K2CO3 and MEA Solutions at 60°C Modeling

A simple thermodynamic model was developed to predict equilibrium and speciation in promoted K2CO3. The model simultaneously solves equilibrium expressions, total mole balances, and a charge balance. Using an un-promoted K2CO3 solution at 60°C as a starting point, equilibrium constants were adjusted to fit model predictions to experimental data with high potassium concentrations. Adjusted constants were represented by the product of the original equilibrium constant and an adjustment factor. Using a least squares regression of the model predictions, the equilibrium constants were altered such that the model fits smoothed Pco2* data at 60°C as extrapolated from Tosh et al. [8]. For a 20 wt% K2CO3 solution, no adjustment was necessary [6]. When compared to 30 wt% K2CO3, the equilibrium constants required a large adjustment demonstrating non-idealities associated with high ionic strength [6]. A similar procedure was followed to match data for the speciation of PZ in the solutions, with each equilibrium constant treated independently. For a 20 wt% K2CO3 solution containing 0.6 m PZ at 60°C, the equilibrium constants were adjusted by matching predictions to NMR speciation data such that the constant for PZ to PZCOO- and the constant for PZCOO to PZ(COO)2 were 75 and 70% of their original values, respectively [6]. The continuous lines in Figure 1 are predictions of the equilibrium model. Throughout the range of loading the model performs well, although there is a slight discrepancy at high loading.

1606 A rate model capable of predicting the flux of CO2 into promoted potassium carbonate solutions was also developed [2,6]. Using a non-linear regression method, the rate model predictions were fit to experimentally determined fluxes by adjusting the rate constants present in Equation 2. The results of the regression and values obtained by Bishnoi [2] for aqueous PZ and MDEA/PZ mixtures are shown in TABLE 1. Rate constants of PZ and PZCOO- used in the model contained temperature dependence (AHa) in the form of an Arrhenius expression based on 298K.

r = {kt,z_on_ [PZIOH-]+ kez [PZ] + kezco o_ [PZCO0- ]}[CO2 ]

(2)

It was found that a low-loading interaction term (kpz-oH) w a s necessary to accurately predict CO2 absorption rates in aqueous K2CO3. With its inclusion, the PZ rate constant is increased by a factor of five from its value in water as reported by Bishnoi [2]. The PZ-hydroxide term at a high concentration of hydroxide, 0.45 M, in 3.6 m K + gives an apparent rate constant 22 times faster than in water. The rate constant for PZCOO- gives satisfactory results when its value in 4.0 M MDEA is used [2]. Previous research suggests the accelerated rate behavior is a result of a catalytic effect of carbonate or of increased ionic strength [4,5,9,10]. Regardless of the mechanism, relative rate constant values show that the CO2-PZ reaction is much faster than the CO2-MEA reaction (kMEA° = 7000 m3/kmol-s) [2].

TABLE 1 SPECIFIC RATE CONSTANTS AT 25°C REGRESSED FROM VARIOUS RATE EQUATIONS, AHA = 3.36E4 KJ/MOL FOR PIPERAZINE AND PIPERAZINE CARBAMATE [2] kpz.OH°

(m6/krnol2-s) [2] 0.0 This Work 2.69e6"* * Not Regressed ** AHa = 0 kJ/mol

kpz °

kpzcoo -°

(m3/kmol-s) (m3/kmol-s) 5.38e4 4.70e4 2.85e5 4.70e4"

As shown by the comparison to 5 M MEA, PZ is an effective promoter of CO2 absorption in aqueous K2CO3. Analysis of equilibrium data indicates that the AHabs of CO2 increases with the addition of PZ to aqueous potassium carbonate. Model predictions indicate that capacity is nearly independent of PZ concentration; conversely, an increase in K2CO3 yields a larger increase in capacity. Proton NMR suggests that PZCOO- is the dominant species at high loading; consequently, it is responsible for most of the reaction rate. Given that PZ reacts much faster than the PZCOO, loading should have a significant effect on absorption rates. REFERENCES

1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Bosch, H., Versteeg, G. F., and Van Swaaij, W. P. M. (1989) Chem. Eng. Sci. 44, 2745. Bishnoi, S. (2000) Ph.D. thesis, The University of Texas at Austin, Austin, TX. Dang, H. (2001) M.S. thesis, The University of Texas at Austin, Austin, TX. Sartori, G. and Savage, D. W. (1983) Ind. and Eng. Chem. Fund. 22, 239. Tseng, P. C., Ho, W. S. and Savage, D. W. (1988) AIChE. J. 34, 922. Cullinane, J. T. (2002) M.S. thesis, The University of Texas at Austin, Austin, TX. Cullinane, J. T. and Rochelle, G. T. Submitted to Chem. Eng. Sci. July 2002. Tosh, J. S., Field, J. H., Benson, H. E. and Haynes, W. P. (1959) U.S. Bureau of Mines, 5484. Laddha, S. S. and Danckwerts, P. V. (1982) Chem. Eng. Sci. 37, 665. Pohorecki, R., Xoan, D. T. and Moniuk, W. (1988) Inz. Chem. Proc. 9, 667.

G E O L O G I C A L STORAGE

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1609

EFFECT OF PRESSURE, TEMPERATURE, AND AQUEOUS CARBON DIOXIDE CONCENTRATION ON MINERAL WEATHERING AS APPLIED TO GEOLOGIC STORAGE OF CARBON DIOXIDE Robert G. Bruant Jr. l, Daniel E. Giammar 2, Satish C. B. Myneni 2, and Catherine A. Peters ~ ~Program in Environmental Engineering and Water Resources, Department of Civil and Environmental Engineering, Princeton University, Princeton, New Jersey 08544 2Department of Geosciences, Princeton University, Princeton, New Jersey 08544

ABSTRACT

CO2 mediated dissolution of silicate minerals and subsequent precipitation of carbonates in deep saline aquifers may allow permanent trapping of carbon dioxide. However, the time-scales and extents of the reactions are poorly understood for CO2 receptor formation conditions. To address these shortcomings, experiments were conducted to investigate the effects of pressure, temperature, and aqueous solution composition on rates and mechanisms of silicate mineral dissolution and carbonate precipitation. A high pressure/high temperature flow-through reactor system was used to derive steady-state dissolution rates of crushed forsteritic olivine. The system allowed continuous monitoring of temperature, pressure, and pH, and periodic sampling of effluent fluids for dissolved ion concentration analysis. Preliminary measurements of dissolution rates indicate good agreement with previously published measurements at ambient conditions. Increasing the pressure from 1 to 100 bar under constant CO2 conditions increased the dissolution rate by ---80%. The same reactions were studied in batch systems using an array of analytical techniques to investigate dissolution mechanisms and secondary precipitate formation. The extent of olivine dissolution in the batch reactors increased with temperature, Pco2 and surface area. Precipitation of magnesium-rich carbonates on reacted olivine was observed at initial magnesite saturation indices greater than 1.6.

INTRODUCTION AND B A C K G R O U N D

Deep (> 1 km) saline aquifer storage of CO2 is a carbon mitigation option that is receiving considerable attention (e.g., [ 1,2]). Associated dissolution of silicate minerals and precipitation of carbonates in receptor formations may allow near-permanent trapping of CO2. While an extensive body of work has been published regarding mineral weathering rates and mechanisms in ambient environments (e.g. [4,5]), less consideration has been given to these topics for conditions present in deep subsurface formations. Mineral reaction rates are often expressed using a simple rate law (e.g., Eqn. 1), accounting for effects ofpH, temperature, and reaction affinity:

r=koe-Eo/RT{H+}n#+(I_e'~Gr/RT),

(1)

where r is the reaction rate, ko is the intensive rate constant, E~ is the apparent reaction activation energy, R is the molar gas constant, T is the absolute temperature, {/-/+} is the hydrogen ion activity (= 10PH), nn+ is

1610 the order of the reaction with respect to the hydrogen ion activity, and AGr is the Gibbs free energy of the reaction [3]. In general, dissolution rates for silicate minerals will be higher at the high temperature and low pH conditions relevant to geologic storage of carbon dioxide than at ambient ground surface conditions. However, effects of pressure and CO2 concentration on dissolution rate are not well understood and not explicitly accounted for in most rate laws. A high pressure/high temperature flow-through reactor system was used to elucidate these effects on the steady-state dissolution rate of forsteritic olivine. Olivine was chosen as a model silicate mineral due to its well-constrained stoichiometry, documented congruent dissolution, and relatively fast reaction rate at ambient conditions. The weathering of Ca- Mg-, and/or Fe(II)-rich silicate minerals in the presence of carbon dioxide offers the potential for formation of carbonate minerals. For example, weathering of forsterite has produced high yields of magnesium carbonate (i.e., magnesite) in aqueous reactors engineered for direct mineral carbonation [6,7]: Mg2SiO4(s) + 2C02(aq) = 2MgCO3(s) + Si02(s). Such mineral reactions may also allow permanent in-situ trapping of CO2 in deep saline aquifers. While it is understood that the spontaneous precipitation of a mineral phase is related to the solution saturation index,

SI: SI - Log,o

),

(2)

where Q is the reaction quotient and Keq is the equilibrium constant, such indices are not well quantified for carbonate mineral formation at CO2 receptor reservoir conditions. High pressure/high temperature batch reactors were used to generate aqueous and solid samples for observation of primary mineral alteration and determination of conditions necessary for secondary mineral precipitation.

MATERIALS AND METHODS

Flow-Through System A 500 cm 3 reaction vessel and 790 cm 3 water/CO2 contacting vessel were constructed from 316 grade stainless steel; all other system materials were chosen for pressure tolerance and inertness (Figure 1). The system had a maximum operating pressure and temperature of 100 bar and 100°C, respectively. Influent water, transferred directly from a deionized water source, was stored in a polyethylene carboy under a He atmosphere. For each experiment, --1.6 g of 53-106/an size fraction San Carlos forsteritic olivine (Fo90, (Mg0.90Fe0.t0)2SiO4) with a specific surface area of---0.15 m E g-i was added to the reaction vessel. System temperature, maintained at 40°C, and influent/effluent pH were continuously monitored. Olivine dissolution rates were inferred from the effluent aqueous concentrations of magnesium, iron, and silicon, the volumetric flow rate, and the total mineral surface area. A suite of four independent experiments was conducted (Table 1). The pH was stabilized at 3.1 by direct addition of HCI to the influent water reservoir. The water/CO2 contacting vessel was used to equilibrate the aqueous influent solution with a pure CO2 headspace (Pco2 = 1 and 100 bar); no CO: delivery to the contacting vessel occurred for CO:-free (i.e., Pco2 = 0) experiments.

Batch System Batch reactions were performed in sealed Teflon-lined digestion bombs and in a Teflon-lined valved reactor (Figure 1). Digestion bombs used dry ice to generate pressure (Pr = Pco2), while a high-pressure syringe pump provided pressure control for the valved reactor. Batch experiments with two size fractions of Fo90 (20-50/zm and 125-250/zm) were conducted at 1 and 100 bar Pco2, a range of temperatures (30, 40, and 95°C), and a range of initial solution compositions. Solution compositions were selected to investigate the influence of common saline aquifer species on the weathering process and to probe the effect of saturation

1611

~_wa~

~

Wa~e

r~ oLo (~) [~ Q

sa.~ Col

,, Pump

Coo.~ll,

CheckValve stirBar PressureGauge

ResislMtyProbe Pump Regulator

r-~'l~ c d T~nq~,~nllueCqnltolSyrian

RTDProbe J'~ pHProbe Irvl.JneFilter I~ Relief Valve I> 1.64. Increasing degrees of magnesite precipitation occurred with increasing saturation indices.

Figure 2: Scanning electron micrographs of forsteritic olivine reacted for 10 days at days at 95°C and 100 bar Pco2 in solutions with varying initial saturation indices for magnesite. Arrows identify magnesite crystals in images with small amounts of precipitation. REFERENCES Bachu, S. (2001). In Geological Perspectives of Global Climate Change, pp. 285-303, Gerhard, L.C., Harrison, W.E., and Hanson, B.M. (Eds). American Association of Petroleum Geologists, Tulsa. Bruant, R. G., Jr., Guswa, A. J., Celia, M. A. and Peters, C. A. (2002). Environ. Sci. Technol. 36, 241A. Lasaga, A. C. (1995). In Chemical Weathering Rates of Silicate Minerals, Vol. 31, pp. 23-86, White, A. F. and Brantley, S. L. (Eds). Mineralogical Society of America, Washington. Wogelius, R. A. and Walther, J. V. (1991). Geochim. Cosmochim. Acta 55, 943. Pokrovsky, O. S. and Schott, J. (2000). Geochim. Cosmochim. Acta 64, 3313. Guthrie, G. D. J., Carey, J. W., Bergfeld, D., Byler, D., Chipera, S., Ziock, H.-J. and Lackner, K. (2001). Geochemical Aspects of the Carbonation of Magnesium Silicates in an Aqueous Medium. First National Conference on Carbon Sequestration. U.S. DOE, Washington. O'Connor, W. K., Dahlin, D. C., Nilsen, D. N., Rush, G. E., Waiters, R. P., and Turner P. C. (2001, Carbon Dioxide Sequestration by Direct Mineral Carbonation: Results from Recent Studies and Current Status. First National Conference on Carbon Sequestration. U.S. DOE, Washington. Wogelius, R. A. and Walther, J. V. (1992). Chem. Geol. 97, 101.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1613

ADVANCED CENTRIFUGAL COMPRESSORS FOR CO2 RE-INJECTION PLANT Akinori Tasakil, Tsunenori Satol, Norihisa Wada 1 ~Turbo-machinery Engineering Department, Hiroshima Machinery Works Mitsubishi Heavy Industries Ltd., 6-22, 4-Chome, Kan-on Shin-machi, Nishi-ku, Hiroshima 733-8553 Japan

ABSTRACT Today, we are dependent on hydrocarbons such as oil and natural gas, that are easily handled, for the majority of our energy requirements. As we burn these hydrocarbons, carbon dioxide (CO2) gas is produced. It is well recognized that CO2 gas is one of the main causes of recent temperature rises in the atmosphere, which is known as "the greenhouse effect". In recent years, not only the technology to save energy and thereby reduce CO2 emissions, but also that to get rid of unwanted CO2, has become prominent. This paper presents and explains the centrifugal compressors developed for CO2 re-injection below ground, as a practical solution to the problem of what to do with unwanted and harmful CO2.

INTRODUCTION The In Salah Gas Project is a joint venture of Sonatrach and BP Exploration Limited set up to produce natural gas from the Algerian Southern Sahara. One of the main environmental initiatives adopted by the In Salah Gas Project to limit greenhouse gas emissions has been to re-inject CO2 removed from natural gas, back into the production reservoir. As a result, the CO2 re-injection compressor manufacturer has had to demonstrate that he has prioritised HSE (Health, Safety and Environment) in all aspects of his design and production activities of this project. This paper describes the features of Mitsubishi Advanced Compressors (MAC) that have been applied as part of the main equipment for this epoch-making plant. Considering their purpose, several unique characteristics applied to these compressors are described.

1614

TRAIN ARRANGEMENT For the driver, a double end drive motor with soft starter was applied, considering environmental and user-friendly issues. Figure 1 shows the train arrangement of this plant. Two main advantages can be seen: Gear losses are minimized by this arrangement; this arrangement allows easy maintenance from both ends on each high pressure and low-pressure compressor.

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Figure 1: Train arrangement of this project STRUCTURE OF COMPRESSOR With its optimized design, MAC ensures several HSE friendly aspects, namely high efficiency, a wide operating range, high stability, stable vibration and easy maintenance. Figure 2 shows a cross section drawing highlighting the main features of MAC. Compared with the CO2 compressors supplied by MHI so far, the compressors applied for this project will be some of the largest centrifugal compressors in operation, when considering the following: 1) Discharge pressure:

203 bar

2) Suction volumetric flow:

37,100 m3/h

3) Required drive power: :

',

11.7 MW ,.

(~) 3-Dimensional Impeller (~) Direct Lubrication Beating O

Overhang Damper

(~) Swirl Canceled Labyrinth Seal (~) Dry Gas Seal ®

Figure 2: Sectional drawing of MAC

Shear Ring

1615

High Efficiency and Wide Operating Range for Saving Energy All impellers have optimized 3-dimensional profiles and are designed in conjunction with stationary parts, which come into contact with the gas flow path. As a result, for example, 85% polytropic efficiency at the 1st stage is achieved. Dry gas seals are installed in all compressors. Dry gas seals minimize gas leakage from the compressor and eliminate the need for a seal oil console.

High Stability Against Shaft Vibration In order to provide high stability against shaft vibration, direct lubrication beatings, an overhung damper and swirl canceled labyrinth seals are installed in the compressors. These combined countermeasures achieve a reduction in exciting force and an increase in damping ability.

Easy Maintenance Vertical split type compressors are applied for these re-injection compressors. With this arrangement, overhaul of the compressors can be done without removal of the main process gas piping. Cartridge-type internal bundles, fixed with shear tings, facilitate maintenance and shorten the time needed for disassembly and reassembly. Special tools for disassembly and reassembly are also prepared, based on safety considerations.

COz Property under High-pressure Condition For CO2 compressors, it is very difficult to predict the gas property, because CO2 gas shows a specific nature, which differs from an ideal gas under, high-pressure. Since Mitsubishi has extensive experience of designing and manufacturing CO2 compressors for UREA plants, actual compressor thermodynamic performance has been well documented in accordance with shop test data up to 235bar, as well as site operation data. From this data, MHI has a better handle on predicting CO2 gas properties over a wide operating range, and can achieve adequate compressor design accordingly.

For this project, the compressor performance will be further

confirmed under full load and full pressure conditions during testing at Mitsubishi's Hiroshima factory.

Elimination of Impeller Resonance Vibration For an impeller operating in high-density gas (a CO2 compressor yields a very high density at the final discharge section, and specific gravity of the gas can be one-third that of water), the effects of virtual mass and damping of the fluid, must be taken into account.

The natural frequency of the impeller in a

high-density gas was obtained by analysis. The results showed that the natural frequency could be significantly lowered to about 64% of that which exists in normal atmosphere. This reduction ratio is introduced as a factor into the design of the impeller.

Soft Start Operation As this site is in a rather isolated location the grid power supply cannot sustain high current demands for long periods. As a result, during the compressor drive motor start-up, a significant reduction of available electricity voltage may occur locally and cause problems for other electric equipment. To prevent this, a soft starter system, i.e. frequency control system, has been applied, limiting the electric current during start up to below

1616 the rated current. This sot~ starter system is shared by two 12MW compressor drive motors. FULL LOAD, FULL PRESSURE STRING TEST Finally all characteristics of these re-injection compressors are going to be verified by the "Full load, Full Pressure String Test" at Mitsubishi's Hiroshima factory, using a closed loop test facility as shown in Figure 3. Not only the mechanical properties but also thermodynamic performance, instability of rotors in very high-density gas, and noise characteristics will be measured to prove adequate performance of these compressors before shipment.

Gas turbine drive string test Steam turbine drive string test Electric motor drive string test Full load I full pressure test

25 MW 14.5 MW 14 MW 450 kglcm2g

Fig. 3: Large size compressor test stand REFERNCES In-Salah Gas pamphlet (not dated) text by Mike Wells Nojima, N., Kanki, H., Morii, S., Kaneko, A., Kawashima, Y. (Oct. 1994) MHI Technical Review Vol. 31 No.3

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1617

REACTIVITY OF INJECTED CO2 WITH THE USIRA SAND RESERVOIR AT SLEIPNER, NORTHERN NORTH SEA I. Czernichowski-Lauriol 1, C.A. Rochelle2, E. Brosse 3, N. Springer 4, K. Bateman 2, C. Kervevanl, J.M. Pearce 2, B. Sanjuan 1, and H. Serra 1 1BRGM, French Geological Survey, av. Claude Guillemin, BP6009, 45060 Orleans Cedex 2, FR 2 British Geological Survey, Kingsley Dunham Centre, Keyworth, Nottinghamshire. NG12 5GG, UK 3 Institut Francais du Prtrole, 1 et 4 Av. de Bois-Prrau, 92852 Rueil-Malmaison, FR 4 Geological Survey of Denmark and Greenland, Oster Voldegaade 10, 1350 Copenhagen K, DK

ABSTRACT

The chemical reactivity of CO2 with a host formation has to be assessed in any CO2 geological sequestration project, as it may affect injection operations and long term CO2 storage potential. At the Sleipner gas field (Norwegian sector of the North Sea), CO2 has been injected since 1996 into a deep saline aquifer (Utsira formation) approximately 1 km below the bed of the North Sea. This paper summarizes results of the geochemical work carried out as part of the 'Saline Aquifer CO2 Storage' (SACS) project, a European research project which aims to monitor the injection operations at Sleipner.

INTRODUCTION The objective of the geochemical work within the SACS project was to determine the potential for chemical reactions between injected CO2, formation water and the reservoir rock (Utsira sand), as these reactions may affect injection operations and long term CO2 storage potential [ 1,2]. For example, besides being trapped as a buoyant supercritical CO2 'bubble' (physical trapping), geochemical reactions with reservoir rock and formation water can trap the CO2 as a dissolved phase (solubility trapping), as bicarbonate ions and complexes (ionic trapping), and carbonate minerals (mineral trapping), according to a terminology derived from Bachu et al. [3]. This can enhance the CO2 storage capacity and have consequences on CO2 migration or immobilisation. A direct approach was used, based on laboratory experiments reacting samples of Utsira sand and formation water with CO2 under simulated reservoir conditions for timescales up to 24 months. Work was divided into three tasks: (i) determination of the initial state of water-rock interaction within the Utsira formation prior to CO2 injection, (ii) laboratory experiments on actual Utsira material, (iii) numerical modelling for the interpretation of the experiments. Such laboratory investigations are particularly useful for the study of shorter-term processes. Although limited in scale and timeframe, laboratory experiments have the advantage that they can help to identify the key geochemical reactions on actual rock material under actual reservoir conditions, which is very important as such reactions are known to be highly site-specific. They are also helpful to test the ability of geochemical codes to reproduce the experimental observations before using them to make long term predictions over experimental timescales up to thousands of years.

1618 BASELINE GEOCHEMICAL CONDITIONS PRIOR TO CO2 INJECTION Knowledge of the 'baseline' conditions of mineralogy, fluid chemistry and water-rock interaction prior to CO2 injection is essential as they provide a reference point from which changes due to the presence of CO2 can be compared and assessed. They are also used to define the experimental conditions, which should reproduce, as closely as possible, actual reservoir conditions. Figure 1 summarizes the geochemical data available at the time of the project. The core sample at Sleipner allowed for detailed mineralogical analyses and determination of transport properties. However, it was heavily contaminated by drilling fluids, and no useable formation water sample could be obtained from it. Only one borehole terminates in the Utsira at Sleipner (the CO2 injection borehole), and unfortunately no produced porewater samples were available from it. The only information about formation fluid chemistry comes from the Oseberg and Brage fields approximately 200 km north of Sleipner.

SLEIPNER • 37~, 8-11 MPt~ 35.40 g/I • 1 m ;RT¢ ( ~ 1-r~J-A23) •

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Figure 1: Baseline geochemical data from the Utsira Formation available during the SACS project Despite the scarcity on data and samples, a reasonable assessment of baseline conditions within the Utsira sand was made by combining information from the Sleipner, Oseberg and Brage hydrocarbon fields. A roughly homogeneous porewater chemical composition throughout the Utsira formation was reasonably assumed and the decision of using the Oseberg analysis as representative of the Utsira formation is presently an acceptable compromise. However, the need for acquiring new data and samples was emphasized.

LABORATORY EXPERIMENTS A range of experiments have been conducted in either 'batch' and 'flow through' equipment to react samples of Utsira sand from Sleipner with a synthetic Utsira porewater based upon a composition from the Oseberg field. A schematic diagram of the batch reactor is presented on Figure 2. The experimental conditions chosen were mainly 37°C and l0 MPa (in-situ temperature and pressure in the Utsira formation at Sleipner), though some experiments were run at 70°C and 10 MPa to enhance the rates of reaction. Durations ranged from one week to two years. Experiments were pressurised with either nitrogen or carbon dioxide. The former 'blank' experiments provided a 'non reacting' reference point from which to compare

1619 the more reactive experiments containing CO2. However, they also helped provide confidence in the baseline conditions within the Utsira formation prior to CO2 injection. The CO2 experiments provided direct information on how CO2 reacted with the Utsira sand and its porewater.

CO2 inlet

H20 outlet

Figure 2: Schematic diagram of the batch reactor used for SACS experiments These experiments have revealed changes in fluid chemistry associated mainly with dissolution of primary minerals. However, direct evidence from mineralogical observations has never been possible despite the high water-rock ratio used for these experiments (10:1), their relatively long duration (up to 2 years) and the higher temperature (70°C) used for some of them. This is because changes were below the resolution of the analytical technique or below the natural mineralogical variation within the sand.

NUMERICAL M O D E L L I N G OF THE EXPERIMENTS Several 'off the shelf' and 'custom-made' geochemical codes were used for this study. The modeling did confirm that the main observed changes in fluid chemistry are associated mainly with the dissolution of minerals. Ion-exchange processes on clays do not seem to be significant. The main reaction observed from the analytical data in the batch and coreflood experiments at 37 and 70°C and confirmed by geochemical modelling is the fast dissolution of carbonate phases (calcite and probably shell fragments) in presence of pressurised CO2. However this mineral is not fully dissolved at the end of the CO2 experiments. As the Utsira sand porosity is approximately 40% and as the carbonate minerals constitute 3.9% of the total rock volume, overall porosity will be little affected by the partial dissolution of calcite. The modelling also confirms that dissolution of silicate and aluminosilicate minerals is a much slower process that is enhanced by CO2. As an illustration, the behaviour of dissolved calcium in the blank and CO2 experiments at 37°C is presented on Figure 3, with comparison of the analytical and modelling results. The best fit was obtained by varying sligthly the solubility of calcite by AlogK = -0.3, which enters the uncertainty range of the determination of this thermodynamic constant.

1620 Total dissolved

calcium

Effect o f t h e u n c e r t a i n t y o n t h e t h e r m o d y n a m i c c o n s t a n t o f c a i c i t e d i s s o l u t i o n (A l o g K = - 0 . 3 )

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Measured Ca (CO2) Measured Ca (Oseberg) Modelled Ca (blank), IogK37°Ccalcite = 1.67 - 0.3 Modelled Ca (CO2), IogK37°Ccalcite = 167 - 0.3

Figure 3" Behaviour of dissolved Ca concentrations during the SACS batch experiments reacting Utsira sand with CO2 at reservoir temperature and pressure (37°C, 10 MPa). CO2 experiment" pressurised with CO2 Blank experiment: pressurised with N2 CONCLUSIONS This study appears to show that observed CO2-water-rock reactions have resulted in relatively little dissolution of the Utsira sand. Most reaction occurred with carbonate phases (shell fragments), but these were a very minor proportion (about 3%) of the overall solid material. Silicate and aluminosilicate minerals showed only slow, and minor reaction. In terms of geochemical reactions, the Utsira sand would appear to be a good reservoir for storing CO2. However further studies are needed to assess the long term storage behaviour within the Utsira formation, and investigate the reactivity of CO2 with the impermeable rocks (caprocks) above the Utsira formation.

REFERENCES Czernichowski-Lauriol, I., Sanjuan, B., Rochelle, C., Bateman, K., Pearce, J. and Blackwell, P. 1(996a). In: Deep Injection Disposal of Hazardous and Industrial Wastes, Scientific and Engineering Aspects, pp. 565-583, J.A. Apps and C.-F. Tsang (Eds), Academic Press, ISBN 0-12060060-9. Czernichowski-Lauriol, I., Sanjuan, B., Rochelle, C., Bateman, K., Pearce, J. and Blackwell, P. (1996b). In: The Underground Disposal of Carbon Dioxide, Chapter 7, S. Holloway (Ed.), Final Report of Joule II Project Number CT92-0031, British Geological Survey. Bachu S., Gunter W.D. and Perkins E.H. (1994). Energy Conversion and Management 35, pp. 269279.

ACKNOWLEDGEMENTS We acknowledge funding by the SACS consortium (Statoil, BP, Exxon, Norsk Hydro, TotalFinaElf and Vattenfall), the European Commission, and national governments. Other project partners are S1NTEF and NITG-TNO.

Greenhouse Gas Control Technologies, Volume lI J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1621

CARBON DIOXIDE SEQUESTRATION IN SALINE BRINE FORMATIONS John M. Andrrsen, Matthew L. Druckenmiller, and M. Mercedes Maroto-Valer The Energy Institute and Dept. Energy & Geo-Environmental Engineering, The Pennsylvania State University, 209 Academic Projects Bldg., University Park, PA 16802. e-mail: [email protected]

ABSTRACT Although brine formations have the largest potential capacity for permanent CO2 sequestration in geologic formations, little is known about the mechanisms of storing CO2 as mineral carbonates in brine. Accordingly, this study focuses on the kinetics of mineral carbonate formation using high-pressure thermogravimetric analysis that mimics the actual conditions found in saline brine formations. The transformation of gaseous CO2 into stable carbonates was investigated at various pressures and temperatures. When considering pressures between 200 and 600 psi and temperatures between 50 and 75°C, the experimental conditions are equivalent to those attainable through CO2 injection into shallow oil and gas wells.

INTRODUCTION Carbon dioxide emissions from US national energy consumption are estimated to increase at an average annual rate of 1.5 percent, from 1,562 million metric tons carbon equivalent in 2000 to 2,088 million in 2020 [1]. Sequestration of CO2, where the greenhouse gas is firstly captured and secondly stored in a permanent medium, could be a viable option to mitigate CO2 emissions [2]. Although CO2 sequestration is not yet an industrial practice in the United States, there exists potential large scale opportunities, such as sequestration in geologic formations that includes solubility trapping, hydrodynamic trapping, and carbonate conversion through reactions with minerals and organic matter [3]. The principle of the carbonation process includes the formation of stable calcium, magnesium, and iron carbonates that are solids and will be stored permanently in the crust of the earth [4]. The minerals necessary for the formation of these carbonates are abundant in saline brine formations, which are widely spread across the United States [5]. There exist three principal methods for sequestering CO2 in geologic formations. First, CO2 gas can be dissolved in underground liquids such as petroleum; a method known as solubility trapping. A second method known as hydrodynamic trapping exists, in which a cap rock can be used to trap CO2 as either a gas or as a fluid. Finally, CO2 may be converted to a solid through reactions with minerals and organic matter. The latter mineral trapping process includes the formation of stable calcium, magnesium, and iron carbonates [6]. This option could lead to a storage route for anthropogenic CO2 emissions without any environmental legacy to future generations. Although brine formations have the largest potential capacity for CO2 sequestration in geologic formations [7], little is known about the kinetics of trapping CO2 in mineral carbonates and is therefore the focus of this study.

1622 BODY OF PAPER

Experimental The brine sample used in this experiment was taken directly from a Pennsylvania gas well and underwent no treatment. The sample was analyzed for carbonate forming elements using an inductively coupled plasma (ICP) emission spectrophotometer. A thermogravimetric analyzer, CAHN TGA-151, was used to simulate conditions in saline aquifers associated with shallow oil and gas wells by varying both pressure and temperature. Brine samples of about two grams were placed into the analyzer and pressurized to the desired pressure using dry CO2 gas. Once the desired pressure was reached, the sample was heated to the desired temperature, while the weight change of the sample was monitored. Any increase in weight was attributed to an uptake of CO2 into the sample as bicarbonate or carbonate formation. A known mass of the un-reacted brine was dried at 95°C to characterize its salts and minerals composition. The resulting dried samples were then ground into a powder and placed into a vacuum oven for approximately 4 hours to remove all remaining moisture. The mass of solids was then weighed to determine the initial solid content of the brine. This procedure was conducted in triplicate to obtain an average solids mass percentage. This value was then used to calculate any increase in solids in the reacted brine samples, which is associated with the degree of carbonation. The solid mass percentage in the reacted samples was calculated by two methods: (i) measuring directly the weight of solids by drying the samples following their removal from the TGA apparatus; and (ii) measuring the weight uptake as reported from the TGA measurements.

RESULTS AND DISCUSSION Table 1 lists the concentration in ppm of the primary carbonate forming elements in the solid fraction of the brine studied. The remaining weigth is mainly sodium chloride (NaC1), while other trace elements, such as barium (Ba) and strontium (Sr), are present in low concentrations.

TABLE 1 CONCENTRATIONOF THE PRIMARYCARBONATEFORMINGELEMENTSIN THE BRINE SALT Element Concentration, ppm (}.tg/g)

Magnesium (Mg)

Calcium (Ca)

Iron (Fe)

3,847.0

35,340.9

140.4

The main reactions of concem are between the CO2 and the highly abundant magnesium and calcium, which are present in the forms of magnesium oxide (MgO) and calcium oxide (CaO), respectively. The formation of the stable carbonates take place in the following two simplified sets of reactions in Equation 1 and 2:

CO2(g) + Mg2+(l)+ 3H200) "-)' MgCO3(s)+ 2H30+0) CO2(g) + 2H20{1) "-)' HCO3(I) + H30+0) HCO30) + Mg"-0) + H200) "-) MgCO3(s) + H30+0) CO2(g) + Ca2+(1)+ 3H20(1) "-)' CaCO3(s)+ 2H30+(1) CO2(g) + 2H20(1) ")' HCO3-(I) + H30+(l) HCO3-(I) + Ca2+(1)+ H20(I) --) CaCO3(s) + H30+0)

(1)

(2)

Both magnesium carbonate (MgCO3) and calcium carbonate (CaCO3), commonly referred to as magnesite and calcite respectively, are geologically stable minerals and are also abundantly found in natural geologic formations.

1623 Figure 1 shows the weight uptake of the brine sample as it was exposed to 300 psi CO2 under isothermal conditions at 55°C for 25 minutes. Under these relatively mild conditions an increase in mass from 1907 mg to 1924 mg, or about 0.9 wt% with no signs of leveling off aider the 25 minutes was observed. Furthermore, it seems like the mass uptake is initially very fast followed probably by a somewhat slower bicarbonate and carbonate formation. This may indicate that a buildup of acidity, as indicated in Equations 1 and 2, may slow down the reaction.

HP-TGA Conditions: 300 psi, 55 °C 1930 1925 1920 ¢E 1915

j

1910

v

r

1905 1900 0

500

1000

1500

2000

Time, sec Figure 1" Weight uptake of the brine at 300 psi under isothermal conditions at 55°C for 25 minutes.

Table 2 compares the weight uptake values observed by measuring the brine solids with those calculated from the high pressure TGA measurements. The solid mass percentage of the un-reacted brine was 17.0-a:0.1%, as found by drying the sample. The solid mass percentage found by drying the sample reacted at 300 psi CO2 under isothermal conditions at 55°C for 25 minutes was 18.1%. This value is very similar to that calculated directly from Figure 1, where the high pressure TGA experiments yielded a 0.9 wt% increase in the mass of solids, which was attributed to mineral carbonate formation. The weight uptake represents around 6.5-5.3% solid weight uptake (1.1/17=6.5% or 0.9/17=5.3%). This weight uptake is rather significant when considering the short timeframe and the mild temperature and pressure over which the reaction was analyzed. Similar data was collected for various pressures between 200 and 600 psi and at isothermal conditions between 50 and 75°C. Furthermore, complimentary techniques that can verify the formation of carbonates, in particular CaCO3, are presently carried out in our laboratory, and these results will be presented. TABLE 2 WEIGHTUPTAKES IN THE BRINE SOLIDS Weight uptake observed by measuring the brine solids (drying)

Weight uptake observed from high pressure TGA measurement

wt%

Uptake solids wt%

wt%

Uptake solids wt%

1.1

6.5

0.9

5.3

1624 CONCLUSIONS The uptake of CO2 into a Pennsylvanian gas well brine was followed using a high pressure thermal gravimetrical analysis apparatus. The brine contained 35,341 ~tg/g Ca2+(1) and 3,847 l.tg/g Mg2+(1) available to form solid carbonates. The rate of CO2 uptake was followed at 300psi and 55°C, presumably forming stable carbonates. Initially there was a rapid increase in mass that somewhat slowed down after about 0.9 wt% uptake. The weight uptake measured from the high pressure TGA was confirmed by of-line weight measurements on the brine after reaction. Although the kinetics of formation of mineral carbonates through the sequestration of CO2 are complicated and yet still unclear, a process for determining a better understanding exists through the use of high-pressure thermogravimetric analysis. The method described here provides continuous data output throughout the duration of the reaction unlike what is attainable when using ordinary pressure vessels.

ACKNOWLEDGEMENTS

The authors would like to thank the Department of Energy and Geo-Environmental Engineering and The Energy Institute at Penn State University for supporting this work.

REFERENCES

1. Energy Information Administration. Energy Consumption by Source, 1949-2000. Retrieved 02/10/2002, from http://www.eia.doe.gov/emeu/aer/txt/tab0103.htm 2. Parson E.A. and Keith D.W., Science 1998, 282 (5391): 1053. 3. Hitchon, B. (1996) Aquifer disposal of carbon dioxide: hydrodynamic and mineral trapping: proof of concept, Geoscience Publishing Ltd., Sherwood Park, Alberta, Canada. 4. Fauth, D.J., Baltrus, J.P., Soong, Y., Knoer, J.P., Howard, B.H., Graham, W.J., Maroto-Valer, M.M. and Andrrsen, J.M. Carbon Storage and'Sequestration as Mineral Carbonates, Chapter 8 in "Environmental Challenges and Greenhouse Gas Control for Fossil Fuel Utilization in the 21st Century", Eds: MarotoValer, M.M.., Song, C., and Soong, Y., In Press. 5. Bergman P.D., Winter E.M., Energy Conversion and Management 1995, 36 (6-9): 523. 6. Office of Science, Office of fossil Energy, US Department of Energy. Carbon Sequestration Research and Development. December 1999. 7. Jones, A. Glass, C., Reddy, T. K., Maroto-Valer, M. M., Andrrsen, J.M. and Schobert, H.H., Prepr. Am. Chem. Soc. Div. Fuel Chem., 2001, 46(1), 321.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1625

THE GEO-SEQ PROJECT: A STATUS REPORT Larry R. Myer ~, Sally M. Bensonl, Charles Byrer2, David Cole3, Christine A. Doughty 1, William Gunter4, G. Michael Hoversten l, Susan Hovorka 5, James W. Johnson 6, Kevin G. Knauss 6, Anthony Kovscek6, David Law 4, Marcelo J. Lippmannl, Ernest L. Majer l, Bert van der Meer 8, Gerry Moline 3, Robin L. Newmark 5, Curtis M. Oldenburg l, Franklin M. Orr, Jr. 7, Karsten Pruess 1, Chin-Fu Tsang I 1Lawrence Berkeley National Laboratory, Berkeley, California; 2National Energy Technology Laboratory, Morgantown, West Virginia; 3Oak Ridge National Laboratory, Oak Ridge, Tennessee; 4Alberta Research Council, Edmonton, Alberta, Canada; 5University of Texas at Austin, Austin, Texas; 6Lawrence Livermore National Laboratory, Livermore, California; 7Stanford University, Stanford, California; 8Netherlands Institute of Applied Geoscience, Utrecht, The Netherlands

ABSTRACT The goals of the GEO-SEQ Project are to reduce the cost and risk of geologic sequestration and decrease the time to implementation. In order to reduce costs, it has been shown that enhanced oil recovery (EOR) methods can be optimized for sequestration, and enhanced gas recovery (EGR) with sequestration, is feasible. An evaluation of the effects of SOx and NOx on geochemical reactions between CO2, water, and reservoir rocks, has been done to assess the use of impure waste streams as a means to reduce overall sequestration costs. In order to reduce sequestration risks a methodology for site-specific selection of subsurface monitoring technologies has been demonstrated, baseline data needed for interpretation of isotopic tracers used to monitor reservoir processes have been developed, and a new definition of formation capacity factor for use in assessing sequestration efficiency has been developed. Code comparison studies are underway for oil, gas, brine and coalbed reservoir simulators for predicting the fate of CO2 in the subsurface. The GEO-SEQ Project has conducted field tests of monitoring technology at CO2 EOR projects in California and New Mexico, and is collaborating on a pilot brine formation sequestration test in Texas.

INTRODUCTION

Initiated in May of 2000, the GEO-SEQ Project is an applied research and development program with the overall goals of: (1) lowering the cost of geologic sequestration; (2) lowering the risk of geologic sequestration; and (3) decreasing the time to implementation of geologic sequestration by pursuing early opportunities for pilot tests and gaining public acceptance. The Project is supported by the U. S. Department of Energy, Fossil Energy (DOE FE) Carbon Sequestration Program through the National Energy Technology laboratory (NETL). Research is conducted by a core team of scientists and engineers from five research institutions in the United States, one in Canada, and one in Europe, working with four private-sector partners: BP, ChevronTexaco, En Cana, and Statoil. In addition, through ongoing collaborations and our advisory committee, the team extends to include other universities and public and private research organizations. Accomplishments to date of the main

1626 activities of the Project are summarized in the following sections. Additional information, including publications prepared by the GEO-SEQ team to date can be found at http://wwwesd.lbl.gov/GEOSEQ/.

CO-OPTIMIZATION OF CARBON SEQUESTRATION AND ENHANCED OIL RECOVERY (EOR) AND ENCHANCED GAS RECOVERY Two studies are focused on reducing sequestration costs by production of oil and gas in conjunction with CO2 sequestration. One effort is focused on modifying existing, and developing new, CO/EOR methods to increase the amount of CO2 stored in the reservoir relative to the amount of oil produced. As a first step, new criteria were developed for selection of candidate oil reservoirs for combined EOR and CO2 sequestration (Kovscek, 2001). Work next focused on specific approaches that could increase CO2 storage while at the same time enhancing oil recovery. Five initial methods are identified: (1) adjust injection gas composition to maximize CO2 concentration while maintaining an appropriate MMP; (2) design well completions (or consider horizontal wells) to create injection profiles that reduce the adverse effects of preferential flow of injected gas through high permeability zones; (3) optimize water injection (timing, injection rates and WAG ratio) to minimize gas cycling and maximize gas storage; (4) consider aquifer injection to store CO2 that would flow rapidly to producing wells if reinjected in the oil zone; and (5) consider reservoir repressurization after the end of the producing life of the field. Reservoir heterogeneity has a major impact on selection and implementation of specific approaches. Current work is focused on quantifying these relationships as well as developing additional co-optimization methods. A second effort focuses on injection of CO2 into depleted gas reservoirs while simultaneously enhancing CH4 recovery and offsetting sequestration costs. The feasibility of carbon sequestration enhanced gas recovery (CSEGR) has been assessed through numerical simulations performed with the TOUGH2 code, incorporating a new equation of state for water-CO2-CH4 mixtures. Initial, 2-D simulations were based on the Rio Vista Gas Field, the largest on-shore-dry-gas field in California. Results showed that significant CH4 recovery could be achieved before CO2 breakthrough and that breakthrough was controlled more by reservoir heterogeneity than mixing (Oldenburg and Benson, 2001). Subsequent 3-D simulations of a more realistic 5-spot well configuration similarly yielded results that were positive for feasibility of CSEGR. Current work is focused on an economic assessment of CSEGR (Oldenburg and Stevens, this volume). A depleted gas reservoir, which has undergone CSEGR, could also be used for gas (CH4) storage. Preliminary simulations suggest that 30% more CH4 can be stored using CO2 as a cushion gas as opposed to the conventional approach.

EVALUATION OF THE IMPACT OF CO2 AQUEROUS FLUID AND RESERVOIR ROCK INTERACTIONS ON THE GEOLOGIC SEQUESTRATION OF CO2 Another approach to lowering costs is to sequester less-pure CO2 waste streams that are less expensive or require less energy to separate from flue gas. The objective of this study is to evaluate the impact of this impure CO2 waste stream on geologic sequestration. To date, the influence of SO2, NO2, and HzS on COz/rock/water interactions has been evaluated for a feldspathic-sandstone and a carbonate reservoir. Simulations equivalent to batch-type (closed-system) reactions have been performed. The impact of the contaminants on dissolution/precipitation and changes in porosity is primarily due to the increase in acidity caused by their addition. The relative impact is given as: SO2>NOz>>HzS>COz. Reactive chemical transport modeling is currently being carried out to assess spatial and temporal impact of the chemical processes identified in the closed-system modeling.

1627 OPTIMIZATION OF GEOPHYSICAL MONITORING TECHNOLOGIES Monitoring the location and movement of CO2 in the subsurface will lower risks of sequestration. This effort focuses on assessing the sensitivity of geophysical methods and demonstrating their applicability for monitoring. The first phase of this effort involved implementation of a numerical simulation-based, three-step, interactive process of reservoir simulation, forward, and inverse geophysical modeling, to evaluate the sensitivity of candidate techniques and design optimum sensor configurations (Hoversten and Myer, 2001). The second major element of this effort is field demonstration of candidate methods. Four different methods are currently being evaluated: crosswell seismic, single well seismic, crosswell electromagnetic (EM), and electrical resistance tomography (ERT). A CO2 EOR pilot operated by ChevronTexaco in Lost Hills, California, provided an early opportunity to test crosswell seismic and EM techniques. High-resolution crosswell seismic and EM surveys were made before and after CO2 injection. Data from three time-lapse surveys were the basis of a joint seismic EM inversion providing quantitative estimates of gas saturation change resulting from CO2 injection (Hoversten et al, this volume). In a parallel activity, the ERT method is being applied in a CO2 EOR project at the Chevrontexaco Vacuum Field, New Mexico. A method in which well casings are used as electrodes for crosswell measurements is being tested. Time-lapse measurements have been made and are currently being analyzed.

APPLICATION OF NATURAL AND INTRODUCED TRACERS IN GEOLOGIC SEQUESTRATION The overall goal of this effort is to provide methods that use natural carbon and oxygen isotopes, and introduced tracers to determine the fate and transport of CO2 injected into the subsurface. Isotopic work has focused on assessing carbon and oxygen isotope changes as CO2 reacts with potential reservoir phases. Results show that the light isotopes (12C; 160) are preferentially adsorbed onto mineral surfaces resulting in an enriched free CO2. This partitioning is large when the solid is coated with hydrocarbons. As CO2 moves through an EOR environment it may become progressively enriched in the heavy isotopes. Model calculations indicate that typical CO2 gas from anthropenic injection sources will exhibit increases in ~3C/~2C ratios due to interaction with rocks and brines because most geological reservoirs are isotopically heavier. Current work is focused on analysis of gas and carbon isotope compositions of samples obtained from the Lost Hills CO2 EOR pilot. Work on introduced tracers has focused on development of a laboratory flow system for study of sulfur hexafluoride (SF6) and a suite of perfluorocarbon (PFT) tracers.

ENHANCEMENT OF NUMEICAL SIMULATORS FOR CO2 SEQUESTRATION IN DEEP UNMINEABLE COAL SEAMS, OIL, GAS, AND BRINE FORMATIONS Two studies are underway to improve simulation models for capacity and performance assessment of CO2 sequestration. The first is focused on coal bed methane (CBM) numerical codes. Work began with definition of the physical processes that need to be included in (CBM) codes. Benchmark problems were then developed, incorporating increasing levels of complexity. The numerical models being tested are CMG's, STARS, CMG's GEM, GeoQuest's ECLIPSE, BP's GCOMP, CSIRO's SIMEDII and ARI's COMET2. Testing of the first two sets of numerical problems has been completed. These numerical problems have now been repeated assuming injection of flue gas (Law et al, this volume). Further information can be found at http://www.arc.ab.ca/extranet/acbml (user name and password can be obtained by contacting David Law; [email protected]). The second effort is a code intercomparison study which has the goal of stimulating further development of models for predicting, optimizing and verifying CO2 sequestration in oil, gas, and brine formations. In Phase I, a set of eight benchmark problems were developed which incorporate a variety of processes of importance in sequestration. In subsequent phases, test problems will evolve to address greater complexity and

1628 validate experimental data. The Phase community, and researchers from nine Norway, Australia, and the Netherlands) (Oldenburg et al, this volume and Pruess

I problems have been widely distributed to the scientific organizations (including researchers from France, Canada, are participating. A first comparison of results has been made et al, this volume).

IMPROVING THE METHODOLOGY AND INFORMATION AVAILABLE FOR CAPCITY ASSESSMENT OF SEQUESTRATION SITES One of the important factors in determining the suitability of sites for sequestration will be the CO2 storage capacity of the formations. This effort first focused on developing a methodology for calculating capacity. Capacity depends not only upon porosity, but also multiphase flow properties, formation geometry and gravity, and geologic heterogeneity. The concept of a capacity factor, which could be used to quantitatively compare the sequestration capacity of specific sites, was introduced. Initial efforts focused on performing an assessment of the sequestration capacity of oil and gas fields and brine formations in California (Benson 2001). More detailed assessments were then carried out for specific sites in the Frio and Oakville Formations in Texas. Results show that gravity-driven buoyancy flow causes a decrease in the capacity of a given volume. Layer-type heterogeneities tend to counteract these effects by causing lateral spreading of the CO2 plume.

FRIO PILOT TEST The GEO-SEQ Project is a collaboration with the Texas Bureau of Economic Geology to conduct a pilot brine formation CO2 injection experiment. The overall objectives of the pilot test are to: (1) adequately characterize a site for CO2 disposal; (2) monitor the behavior and migration of CO2 behavior; (3) develop conceptual models of CO2 behavior; (4) develop expertise in design and performance of CO2 disposal facilities; and (5) provide information needed to characterize conditions adverse to long-term containment of CO2. Current work is focused on test design. GEO-SEQ investigators are performing reservoir simulation, geophysical simulations and geochemical calculations in support of the design of the CO2 injection strategy and selection of monitoring techniques. ACKNOWLEDGEMENTS Support was provided by the Assistant Secretary for Fossil energy, Office of Coal and Power Systems through the National Energy Technology Laboratory of the US Department of energy under Contract No. DE-AC03-76SF00098. REFERENCES Benson, S. (2001) in Proceedings of Fifth International Conference on Greenhouse Gas Control Technologies, Williams, et al (Eds). CSIRO publishing, pp. 299-304. Hoversten, G. and Myer, L. (2001) in Proceedings of Fifth International Conference on Greenhouse Gas Control Technologies, Williams, et al (Eds). CSIRO publishing, pp. 305-310. Kovscek, A. (2002) Petroleum Science and Technology 20(7 and 8), pp. 841-866. Oldenburg, C. and Benson, S. (2002) SPE 74367, presented at SPE International Petroleum Conference and Exhibition, Villahermosa, Mexico February 10-12.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 NERC. Published by Elsevier Science Ltd. All rights reserved

1629

THE lEA WEYBURN CO2 MONITORING AND STORAGE P R O J E C T - THE EUROPEAN DIMENSION J. B. Riding l, I. Czemichowski-Lauriol 2, S. Lombardi 3, F. Quattrocchi 4, C. A. Rochelle l, D. Savage5 and N. Springer 6 ~British Geological Survey, Keyworth, Nottingham, NG12 5GG, UK* 2Bureau de Recherches Geologiques et Minieres, BP 6009, 3, Avenue Claude Guillemin, 45060 Orleans Cedex 2, France 3Dipartimento di Scienze della Terra, Universita di Roma 'La Sapienza', P. A. Moro 5, Roma, 1-00185 Italy 4Istituto Nazionale di Geofisica e Vulcanologia, INGV Sezioni di Roma, Via di Vigna Murata 605, 00143, Rome, Italy 5Quintessa Limited, 24 Trevor Road, West Bridgford, Nottingham, NG2 6FS, UK 6Geological Survey of Denmark and Greenland, Oster Voldgade 10, DK-1350 Copenhagen K, Denmark * - with the permission of the Executive Director, British Geological Survey (NERC).

ABSTRACT The IEA Weyburn CO2 Monitoring and Storage Project is currently analysing the effects of a miscible CO2 flood into a carbonate reservoir rock at a mature onshore Canadian oilfield. Anthropogenic CO2 is being injected as part of an enhanced oil recovery operation. The European contribution includes the analysis of the long term safety and performance of CO2 storage via construction of a Features, Events and Processes (FEP) database. This will allow the integrity of deep storage of CO2 in sedimentary rocks to be investigated objectively. Initial work has also been focussed on better understanding the pre-injection hydrogeological and geochemical conditions in the reservoir in order to recognise changes resulting from injection of the CO2. The baseline studies also include analysing gas concentrations in soil and groundwater to determine potential migration pathways; two soil gas surveys were undertaken in July and September 2001. The CO2 distributions are irregular and reflect anthropogenic or near surface phenomena and seasonal variations in CO2 fluxes are present. There are no correlations between gas anomalies and injection wells or pipelines. Changes from these baseline conditions as a result of CO2 injection are also under investigation and will be the focus of future activities. Geochemical experiments, predictive computer modelling, microseismic monitoring and soil gas surveys will be carried out to investigate CO2 migration pathways and the rate and extent of chemical reactions of the injected CO2 with the host formation and adjacent strata.

1630 INTRODUCTION The IEA Weybum CO2 Monitoring and Storage Project is a collaborative investigation involving geoscientists from North America and Europe and is co-ordinated by the Petroleum Technology Research Centre (PTRC) in Regina, Canada [ 1]. It is studying the geological storage of CO2 during an enhanced oil recovery (EOR) operation at the Weybum oilfield, Canada. By the end of this phase of EOR, it is expected that approximately 20 million tonnes of anthropogenic CO2 will be permanently stored deep underground. Climate-warming greenhouse gas emissions will have been reduced in an efficient and cost-effective manner. The objectives are to enhance our understanding of the deep underground storage of CO2 via geoscientific monitoring. Furthermore, it is intended to promote international collaboration on carbon management research between researchers in Canada, the USA and Europe. The European arm of project is partly funded by the European Commission (EC).

THE WEYBURN OILFIELD - GEOLOGY AND ENHANCED OIL RECOVERY The Weybum oilfield is located in southern Saskatchewan, Canada (Figure 1A) and was discovered in 1954. It covers approximately 70 square miles of prairie and is operated by the EnCana Corporation (formerly PanCanadian Resources). Oil is recovered from the uppermost Midale Beds of the Charles Formation, a succession of upwards shoaling, shallow marine carbonate-evaporite sediments of Mississippian age. The Midale Vuggy unit represents open marine conditions and is overlain by the shallow water dolomitic mudstones of the Midale Marly Beds, which contain the greatest remaining oil reserves and is now the target for the miscible CO2 flood (Figure 1B). a

b N

• Regina

0

co,

100 km

Injection

Weybum

'

'

Manitoba

w.,

I ILL//F~du~o. ~:~. ~ll~ we,,

_el-- I Figure 1: a - the location of the Weybum oilfield and the route of the CO2 pipeline, b diagram illustrating how a miscible CO2-EOR flood produces incremental oil. At Weybum, the depth to the reservoir unit is c. 1400 m.

Since 1964, water injection has been the preferred secondary recovery mechanism. However, recently installed CO2-EOR operations are considered crucial to the future economic life of the field. The Midale Vuggy Beds proved more permeable than the overlying Midale Marly Beds and consequently have been more efficiently swept during the waterflood operation. It is hoped that the miscible CO2-EOR operation will significantly extend the life of the Weybum Field by the production of 130 million barrels

1631 of incremental oil (Figure 1B). Injection of CO2 commenced during September 2000. Initially, injection is in 17 patterns of nine wells each at the west end of the Weyburn Unit; this CO2 flood will roll out south-eastwards until 75 patterns have been flooded. The CO2 is a by-product of the coal gasification process and is supplied directly to Weyburn by the Dakota Gasification Company via a 330 km long pipeline from the Great Plains Synfuels Plant, Beulah, North Dakota, USA (Figure 1A) [ 1, 2].

THE ORGANISATION OF THE EUROPEAN PART OF THE PROJECT

Work Package I - Long Term Safety and Performance of C02 Storage The aim is to provide a means by which data can be integrated to give an assessment of the safety and economics of CO2 injection at Weyburn. Furthermore, a Features, Events and Processes (FEP) database will be devised and the economics and storage potential of the Weyburn Field comprehensively appraised. The construction of a FEP database is the starting point for safety assessment studies. Natural analogue data obtained through the NASCENT project [3] will also be incorporated. Genetic FEP descriptions for CO2 storage and a Weyburn specific FEP sub-set are currently being produced. Placing the economics of the Weybum EOR/storage operation into a European context are also being investigated.

Work Package 2 - Definition of Baseline Hydrogeological, Hydrochemical and Petrographical Conditions The aim of this package is to define the pre-CO2 injection hydrogeological, hydrochemical and petrographical conditions in the Weyburn reservoir unit at a local and regional scale. A comprehensive understanding of baseline conditions will allow the recognition of changes resulting from the miscible CO2 flood and the determination of the ultimate fate of the injected CO2. To understand the potential migration of CO2, the studies of baseline hydrogeological data from Weyburn have investigated both fluid flow within and outside the reservoir. Studies on baseline fluid chemical data from Weyburn aims to model the initial chemical environment within the reservoir, including the water-rock system and minerals that may react with reservoir fluids under high CO2 pressure. Baseline mineralogical data are also being analysed to assess the initial chemical environment and to identify core material within the CO2 flood area for use in hydrothermal experiments. Experimental geochemical studies on core samples from the first CO2 flooding area are being carried out to ascertain key fluid properties. A further aspect of these baseline studies is to determine the pre-injection regional gas fluxes and concentrations in both soil and groundwater. This will improve the understanding of fluid-flow pathways throughout the Weyburn oilfield. A variety of dissolved and free gases and elements have been studied; these help to determine the baseline and allow potential rapid transport pathways to be identified. Furthermore, elemental studies have analysed baseline water-rock interactions. Part of this task is to investigate whether soil gases and groundwater analyses can be used to identify the position of near surface features that may connect with the reservoir at depth. Seismic profiles were examined for faults, which may conduct gases and liquids above the reservoir, however none, which outcrop, were found. Consistent with this, the soil gas anomalies measured at Weyburn do not follow linear trends. The CO2 distributions reflect

1632 both the origins and natural reactions which typify CO2. The majority of the CO2 anomalies may be explained by anthropogenic or near surface phenomena. There is no correlation between these CO2 anomalies with the injection wells or the underground CO2 pipelines. Furthermore, the expected seasonal variations in CO2 flux data have been discerned. Measurements taken in September 2001 proved lower than those measured in July 2001. These differences are related to seasonal variations in soil humidity, vegetation and agricultural activities. Work Package 3 - Define Changes to Baseline Hydrochemical, Hydrogeological and Petrographical Conditions Resulting from COz Injection This part of the project has recently started to investigate the effects of the injection of CO2 into the Weybum reservoir, particularly those impacting upon the hydrogeological, hydrochemical and petrographical properties of the rock. Predictive computer modelling to assess the chemical impact of CO2 over a variety of temporal and spatial scales is ongoing. This will be supported by observations from laboratory experiments reacting with Weybum Rock and fluid samples, field geochemical monitoring and natural analogues. It is also intended to test whether microseismic monitoring is useful for locating real time fracture generation and fluid flow pathways stimulated by EOR injection. Re-surveys of soil-gas concentrations will also be undertaken to compare with baseline results and test whether any changes are linked to CO2 injection.

CONCLUSIONS The European part of the IEA Weybum CO2 Monitoring and Storage Project will garner scientific and technical knowledge related to an industrial miscible CO2 EOR operation. It is intended to serve as a model, which can be applied elsewhere. The participants expect that results from this project will help guide policy development on greenhouse emissions from industrial scale energy generation via deep underground storage. REFERENCES Moberg, R. (2001). Greenhouse Issues 57, 2. Malik, Q.M. and Islam, M.R. (2000). In: Society of Petroleum Engineers/Department of Energy Symposium on Improved Oil Recovery 2000, Tulsa, Oklahoma, 3-5 April 2000. Pearce, J.M., Nador, A. and Toth, E. (2002). Greenhouse Issues 58, 6.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1633

PRELIMINARY CHARACTERISATION OF REGIONAL HYDROGEOLOGY AT THE CO2 SEQUESTRATION SITE OF WEYBURN (SK- CANADA) Y.M. Le Nindre l, I Czemichowski-Lauriol l, S. Bachu 2, and T Heck 3 1BRGM-French Geological Survey, BP6009, 45060 Orlrans Cedex 2, France 2 Alberta Geological Survey, 4th Floor, Twin Atria, 4999-98 Avenue Edmonton, Alberta T6B 2X3 Canada 3 North Dakota Geological Survey, 600 East Boulevard Avenue, Bismarck, ND 58505-0840 USA ABSTRACT

The EU funded project ENK5-CT-2000-00304"Weybum" is carried out in close co-operation between European and American scientists, with the objective to elaborate, from a case study, a project strategy applicable to European sites. For this target, its primary expected outcome is to enhance understanding of the underground sequestration of CO2 associated with EOR in the context of carbonate reservoir, and to evaluate the impact of this sequestration on the reduction of greenhouse gas emissions. The investigations are more specifically designed to evaluate the potential long-term migration pathways and reactivity of CO2 with the host formation, basically controlled by the regional hydrodynamics and geochemistry of aquifer systems. In a block of 240x230x4.8 Km centred on Weyburn, a first phase of investigation has provided the major structural and hydrogeological features which have been modelled for a set of aquifers. Results demonstrate that flows, mostly updip, are driven both by elevation of recharge area and superimposed effect of salinity and subsequent density.

INTRODUCTION

The Weybum oilfield, operated by PanCanadian, is located in southern Saskatchewan (Canada - figure. 1) and covers -~180 Km 2. It was discovered in 1954, production started in 1955. The peak production was reached in 1965 with 7,500 m3/d. Enhanced oil recovery (EOR) involved successively three fluid drives: primary (water), secondary (water flood in 1962), and tertiary CO2 flood (Sept. 2000). A 330-km pipeline from the Dakota Gasification Company's plant, located near Beulah, North Dakota, USA, supplies 5000 t/d CO2. •!~7........i:.~Li!. :i

%

,,; ,-.,,

Figure 1: Location map of the Weybum field

1634 It is expected that some 20 Mt of anthropogenic CO2 that would otherwise be released into the atmosphere will be permanently sequestered deep underground. Therefore, this site was selected for the Weyburn C02 monitoring project, a current research and demonstration project of the International Energy Agency Greenhouse Gas Programme. GEOLOGICAL

S E T T I N G

From a geological aspect, the Weybum field is located at the northeastern edge of the Williston basin, which is shared between Canada and the U.S. Oil is produced from two reservoir zones, "marly" and "vuggy"(respectively 6 and 15 m thick) within the Mississipian Midale beds at a depth of 1450m. In order to set the Weyburn field in its regional context, structure, hydrogeology and water chemistry were first compiled from published data at the basin scale (e.g.: Alberta Geological Survey [ 1], Bachu and Hitchon [2], U.S.G.S.[3], Rostron et al. [4]). The construction of a reference section and of a correlation chart gives the correspondence of lithostratigraphy and hydrostratigraphy at Weyburn, and throughout the Williston basin, accounting for facies variations through a great number of geological formations. The study, is focused on a block of 240x230 Km 2 (48.5o-50.5 ° lat. N, 102.0°-105.25 ° long. W) centred on Weyburn, and coveting the structural interval from the top of the Precambrian basement to the ground surface, i.e. ~4800m. It extends mainly in Saskatchewan, northward of 49°N lat., but and also in North Dakota and Montana, on 0.5°lat. Structure, pressure and hydrochemical digital data originate from the Saskatchewan Energy and Mines, Alberta Geological Survey and North Dakota Geological Survey. Structural surfaces, total dissolved solid concentrations and potentiometric surfaces were modelled using geostatistics (GDM® BRGM software) and a set of georeferenced grids. The geological structure of the area is roughly a monocline southward or south-westward, with two lowangle major unconformities truncating the strata updip: - the Mississipian subcrop underneath the pre-Triassic (Lower Watrous) unconformity, - the sub-Mannville (Lower Cretaceous) unconformity The oil reservoir in the Midale beds and overall, the Mississippian aquifer (Madison aquifer), are capped by the Midale Evaporite (where present) and shale and anhydrite of the Triassic Lower Watrous. However, the trap is also hydraulic as shown further by the potentiometric surface of the Mississippian aquifer. Water flooding is operated by tapping almost-fresh water from the broad, overlying Mannville aquifer and injecting it into the "vuggy" zone of the Midale beds (figure 2). @- l l r w $

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1635 MODELLING OF STRUCTURE AND HYDROGEOLOGY Structure To reconstruct the structure, formation tops (from the Upper Albian Viking Aquifer to the Deadwood Fm., i.e., Cambro-Ordovician Aquifer), were modelled from well control data (figure 3). Three sets (structure, salinity, hydraulic heads) of eight maps corresponding to the major aquifer systems were produced by krigging: Upper Cretaceous, Albian, Lower Cretaceous, Middle Jurassic, Mississippian, Upper Devonian, Middle Devonian, and CambroSilurian.

Figure 3: Elevation of the pre-Triassic unconformity (m) Total Dissolved Solid (TDS) The Palaeozoic aquifers exhibit high and variable salinity values due to fresh water influx from the northeast and formation-salt dissolution, whereas the Meso-Cenozoic aquifers have low gradients and salinity, except for some Jurassic horizons where anhydrite is present. The TDS map of the Mississippian aquifer (figure 4) shows a steep salinity gradient in the Weybum area. Those values are in agreement with the recent fluid analyses performed within this project. Brines concentrate in the southern zone. Low salinity values in the north are partly superimposed with the area where the Devonian Prairie Evaporite has been dissolved.

Area of

dissolution of the Prairie

evaporite

25 Km

Figure 4: Salinity of the Mississippian aquifer

1636 Hydraulic Heads Hydraulic heads of the eight aquifers were calculated from DST pressures accounting for water density according to the above TDS distribution. Although the overall subsurface flows are dominantly oriented SW-NE, contrasts of density may induce deep local modifications of pathways and hydraulic traps. Horizontal flows and vertical leakage are controlled by both topography and salinity. The potentiometric surface of the Mississippian (figure 5), is deformed by the effect of brine concentration and of fresh water influx by-passing northward. Therefore, the Mississippian aquifer becomes over-pressured compared to the Mannville. This configuration is important to consider when investigating the potential upward CO2 migration and chemical incidence of water mixing by flooding.

Figure 5: 3D view of the Mannville and Mississippian potentiometric surfaces ACKNOWLEDGEMENTS This study is supported by the EU funded project ENK5-CT-2000-00304"Weybum" and the IEA "Weybum CO2 Monitoring Project". Geological setting: thanks to Saskatchewan Energy and Mines. REFERENCES [ 1]

[2] [3] [4]

Alberta Geological Survey (1994) Geological Atlas of the Western Canadian Sedimentary Basin. Compiled by Grant Mossop and Irina Shetsen. http ://www.ags.gov.ab.ca/ags pub/atlas_www/atlas.htm Bachu S. and Hitchon B. (1996) A.A.P.G. Bulletin, 80, 2, pp. 248-264 U.S.G.S (1996) The Ground Water Atlas of the United States, segment 8, Hydrologic investigations Atlas 730-I, U.S. Geological Survey, Reston, Virginia, Rostron B.J., Holmden C. and Kreis L.K. (1998) Sask. Geol. Soc. Sp. Pub. n°13, pp. 267-273

Greenhouse Gas Control Technologies, Volume lI J. Gale and Y. Kaya (Eds.) Crown Copyright © 2003 Published by Elsevier Science Ltd. All rights reserved

1637

USE AND FEATURES OF BASALT FORMATIONS FOR GEOLOGIC SEQUESTRATION B. P. McGrail 1, A. M. Ho 2, S. P. Reidel l, and H. T. Schaef I Applied Geology & Geochemistry Department, Pacifc Northwest National Laboratory- Battelle, P.O. Box 999, Richland, Washington, USA 2 Department of Geology, Eastern Oregon University, La Grande, Oregon, USA

ABSTRACT Extrusive lava flows of basalt are a potential host medium for geologic sequestration of anthropogenic CO2. Flood basalts and other large igneous provinces occur worldwide near population and power-producing centers and could securely sequester a significant fraction of global CO2 emissions. We describe the location, extent, and general physical and chemical characteristics of large igneous provinces that satisfy requirements as a good host medium for CO2 sequestration. Most lava flows have vesicular flow tops and bottoms as well as interflow zones that are porous and permeable and serve as regional aquifers. Additionally, basalt is ironrich, and, under the proper conditions of groundwater pH, temperature, and pressure, injected CO2 will react with iron released from dissolution of primary minerals in the basalt to form stable ferrous carbonate minerals. Conversion of CO2 into a solid form was confirmed in laboratory experiments with supercritical CO2 in contact with basalt samples from Washington State. FLOW TOP

INTRODUCTION Upper

Capture of CO2 from flue gases and subsequent geologic sequestration offers promise for controlling anthropogenic CO2 emissions, reducing the cost of managing climate change, and preserving the viability of fossil fuels. Site assessments for geologic sequestration of CO2 have been conducted for the mid-West to mid-Atlantic region of the U.S. [ 1] and at a few other locations around the world. Surprisingly, basaltic rocks have not attracted attention as potential host formations. Iramense basalt flows occur around the world and are recognized as playing an important role in the global carbon cycle [2-5]. Large igneous provinces (LIPs) represent immense outpourings of marie (iron- and magnesium-rich) magmas and include continental flood basalts (CFBs), volcanic passive margins, geeanic plateaus, and their associated intrusive rocks.

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The internal flow features in CFB lavas make them attractive Figure 1: Major internal features of a Cotargets for CO2 sequestration. Internal features formed during lumbia River Basalt Group lava flow the solidification of a lava flow result from variations in cooling rates, degassing, thermal contraction, and interactions with water. These features may be continuous for large distances, though their thickness is often highly variable. The uppermost section of a basalt flow (see Figure 1) consists of vesicular or brecciated basalt and is the principal feature into which CO2 would be injected. The thickness of the vesicular portion of

1638 a flow may range from a few centimeters to almost the entire flow thickness, but most vesicular flow tops comprise 15 to 30% of the flow's thickness. Joints are the dominant intraflow structures and form as a result of tensional stress induced from differential thermal contraction during cooling. Colonnade and entablature joints [6] form roughly vertical "columns" of rock that provide a possible pathway for CO2 to leak to an overlying flow. However, saprolites (extensively weathered soil) and low-permeability sedimentary interbeds that occur in most basalt flows form important confining horizons. The interior of a basalt flow is also quite dense and of low permeability, potentially acting as a caprock between flows. Major chemical and isotopic differences between the groundwaters in different Columbia River Basalt Group (CRBG) flows [7] do indicate effective seals between flows that would suggest limited potential for vertical migration of gas stored within deep basalt interflow zones. TABLE 1 AREAL EXTENTAND VOLUMESOF MAJORLIPs LIP

Location

Area, km 2

Volume, kin3

CRBG, ColumbiaRiver Basalt G r o u p

Northwestern U.S.

200,000

224,000

DEC, Deccan Traps

India and Pakistan

600,000

512,000

EME, EmeishanBasalts

Southwest China

>250,000

>300,000

HCB, Hannuoba-ChifengBasalts

Northeastem China

20,000

1400"

2,300,000

9,100,000

160,000

640,000*

1,300,000

6,600,000

500*/400*

50*/40*

KER, KerguelenPlateau

Southern Indian Ocean

KEW, KeweenawanBasalts

Northcentral U.S.

NAVP, North Atlantic VolcanicProvince

UnitedKingdomand Greenland

NB/HB, Newark Basin and Hartford Basin NortheasternU.S. OJP, OntongJava Plateau

Southwestem Pacific

1,900,000

44,400,000

PEP, Paranh-EtendekaProvince

Brazil, Namibia, and Angola

2,200,000

>l,000,000

SIB, SiberianTraps

Eastern Siberia

340,000

400,000

YET, Yemen-EthiopianTraps

Yemen and Ethiopia

>600,000

>350,000

* Estimated. Volumes estimated from area and average thicknesses o f 70 m (HCB), 4 km (KEW), and 1O0 m (NB/HB).

GLOBAL SURVEY OF LARGE IGNEOUS PROVINCES Details regarding the areal extent and volume of LIPs around the world are given in Table 1. Of significance are the large basalt flows located in the U.S., China, and India. Because China and India are already major CO2 emitters and will surpass the U.S. in total greenhouse gas emissions within the next 10 to 25 years [8,9], these formations might provide an important sequestration option for CO2 in these countries. BASALT FORMATIONS IN THE U.S. There are major basalt flows in four regions of the U.S. (see Figure 2) that might be attractive targets for carbon sequestration. Along the eastern margin of North America, the Newark Supergroup contains all sediments and volcanic rocks preserved in these ritt basins. Tholeiitic lava flows are found only in the northern- and western parts of these basins. Of the basins containing basalt, the Newark and Hartford basins are the largest and most studied. Both basins contain three basalt sections separated by sediments and a deep, genetically related sill [ 10]. The Watchung Basalts are interbedded with 170-500 m of sediments [ 11 ]. Individual flow thicknesses are up to 100 m (Holyoke basalt in the Hartford basin); the thickest of the Watchung flows is the Preakness flow (up to 180 m thick) [12]. This group ofbasalts is also located near a significant concentration of fossil fuel power plants (Figure 2). The Central Atlantic Mafic Province (CAMP) is an early Mesozoic province related to the opening of the Atlantic Ocean that extends in the U.S. from the northeast along the Appalachians to the Gulf of Mexico. The South Georgia Rift is a complex terrance of rift basins with subbasins up to 100 km wide and over 7 km deep. The basins are filled with sediments and volcanics. Like the Newark basin, the fill is typically about 6 km thick as interpreted from seismic reflection lines. Much is sediment, but mafic igneous rocks are also

1639

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Figure 2: Distribution of major sedimentary and basalt formations in the U.S. along with coal, oil, and natural gas power plants. Darker areas represent basalt flows, lighter areas deep sedimentary formations. present [ 13]. Although little is known about the structure and extent of this flow, the region does intersect a concentrated area of power plants (Figure 2). The 2500-km-long mid-continent rift system in central North America comprises the Keweenawan Supergroup. Keweenawan basalts are composed of at least 300 flows extruded into 7 or 8 separate rift basins [ 14]. They are interbedded with sandstone units [ 15]. At Mamainse Point in eastern Lake Superior, over 350 flows are exposed that span most of the volcanic history of the rift system. The CRBG, which is part of the larger Columbia Plateau Province shown in Figure 2, is one of the most well-studied LIPs in the world, despite its small size relative to other known CFBs (Table 1). The group covers more than 200,000 km 2 of Washington, Oregon, and Idaho with a total volume of over 224,000 km 3. Each flow is from a few tens of meters to 100 m thick. Through studies of the basalts and the basalt aquifer systems for nuclear waste remediation at the Hanford Site and for natural gas storage [ 16], a large body of information is available to provide an estimate of the CO2 storage capacity in the CRBG. Assuming an interflow thickness of 10 m with an average porosity of 15% and 10 available interflow zones, at an average hydrostatic pressure of 100 atm the storage potential is greater than 100 Gt CO2. This capacity is more than sufficient to sequester the entire emissions of the northwestern U.S. for the foreseeable future. MINERAL TRAPPING IN BASALT There is insufficient Ca, Mg, and Fe in the rocks that make up a typical sedimentary formation to support significant mineral trapping [ 17]. Consequently, the injected CO2 will be stored essentially permanently in a supercritical state that will be subject to slow leakage processes and to low-probability but high-risk catastrophic releases. Injection of CO2 or an untreated flue gas stream into a basalt aquifer will lower the typical brackish basalt groundwater pH from between 8.5 and 9.2 to 3.5 or lower. Iron-rich phases such as pyroxene, olivine, spinel, and glassy mesostasis are unstable at low pH and dissolve. The ferrous iron released to the aqueous phase reacts with CO2 to form ferrous carbonate minerals such as siderite that permanently sequester CO2. To test this hypothesis and to obtain data on the potential rate of carbonate mineral precipitation, laboratory experiments were performed with CRBG samples. To track CO2 consumption as a function of time, we elected to monitor the change in CO2 pressure as a function of time in a batch reactor system. However, a very important consideration in this approach is to ensure that any observed pressure drop can be attributed to mineralization reactions and not to slow leakage of CO2. To solve this problem, we designed a doublecontained pressure vessel system. A high-pressure reactor is placed inside a sealed aluminum container. The inner vessel can be pressurized to 3000 psi with CO2 and the outer vessel is evacuated and then backfilled with N2 or He at low pressure (1 psi). Over the course of an experiment, the gas composition in the

1640

aluminum vessel is analyzed with gas chromatography. Any leakage of CO2 from the high-pressure reactor is detected from an increase in CO2 concentration.

1600 1400

N2 Pressurization

N 2 Pressurization _ . _ . _ ~ i ~

[

The pressure vessels were packed with 25 g of basalt "~ 1000 and 12 mL of deionized water, thereby forming a wa- ai 800 ter-saturated porous medium in the vessel. A hydraulic syringe pump was then used to pressurize the vessel with CO2 to approximately 900 psi at room tempera- n" 400 ture. The mass change after pressurizing with CO2 200 was recorded, and typically about 4 g of CO2 was o charged into the vessel. The pressure vessel was then o 500 1ooo 1500 2000 placed into its aluminum outer containment vessel, Time, hr which was sealed, evacuated, and then pressurized to 1 Figure 3: Pressure as a Function of Time for psi with N2 gas. The entire assembly was then placed Static Tests with Two Different Basalt Samples into a controlled temperature water bath at 90°C. An electronic pressure transducer connected to the inner vessel was used to track the pressure during the experiment. Figure 3 shows the pressure drop data as a function of time for tests with the different basalt samples. Upon raising the temperature to 90°C, the pressure increased to approximately 1500 psi, which was the target starting pressure for these tests. For the Rocky Coulee sample, the pressure dropped rapidly over the course of the test, as shown in Figure 3, falling below 400 psi after 200 hr. The experiment was terminated at this point and the remaining gas phase CO2 vented, which was measured from mass change to be 0.4 g. The vessel was then immediately pressurized with N2 gas to 1026 psi to recheck for possible leakage through the pressure transducer fittings (no CO2 was detected in the outer containment vessel). The results (Figure 3) show that a constant N2 gas pressure was maintained for over 100 hours after pressurization. Thus, leakage of CO2 from the pressure vessel cannot be the cause of the large pressure drop observed for this test. In contrast, the Sentinel Bluff basalt shows slower reaction kinetics. The Rocky Coulee sample is from a lava flow top and has small micropores that give it a 3X higher overall surface area than the Sentinel Bluffs sample, which is from a flow interior. The larger surface area of the Rocky Coulee sample gives a higher release rate of iron and so more rapid consumption of CO2 in forming carbonate minerals. The data confirm our hypothesis regarding the potential for basalt formations to rapidly convert injected CO2 into solid mineral form. REFERENCES 1. Gupta,N., Wang, P., Sass, B., Bergman, P. and Byrer, C. (2001). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 385-390, Williams, D.J., Durie, R.A., McMullan, P., et al. (Eds). CSIRO Publishing, Collingwood, Australia. 2. Varekamp,J.C., Kreulen, R., Poorter, R.P.E. and Vanbergen, M.J. (1992) Terr. Nova 4 (3), 363. 3. Brady, P.V. and Gislason, S.R. (1997) Geochim. Cosmochim. Acta 61 (5), 965. 4. Tajika, E. (1998) Earth Planet. Sci. Let. 160 (3-4), 695. 5. Retallack, G.J. (2002) Philos. Trans. R. Soc. Lond. Set. A-Math. Phys. Eng. Sci. 360 (1793), 659. 6. Tomkeieff,S.I. (1940) Bull. Volc. 6, 90. 7. DOE (1988). Site Characterization Plan, Reference Repository Location, Hanford Site, Washington. DOE/RW-0164, Vol. 2, U.S. Department of Energy, Washington, D.C. 8. Williams,R.O. (1993) Energy Convers. Manag. 34 (9-11), 719. 9. Bach, W. and Fiebig, S. (1998) Energy 23 (4), 253. 10. Seidemann, D.E., Masterson, W.D., Dowling, M.P. and Turekian, K.K. (1984) Geol. Soc. Am. Bull. 95 (5), 594. 11. Puffer, J.H., Hurtubise, D.O., Geiger, F.J. and Lechler, P. (1981) Geol. Soc. Am. Bull. 92 (4), 155. 12. Puffer, J.H. and Volkert, R.A. (2001) J. Geol. 109 (5), 585. 13. McBride, J.H. (1991) Tectonics 10 (5), 1065. 14. Green, J.C. (1982). In: Geology and Tectonics of the Lake Superior Basin, pp. 47-55, Wold, R.J. and Hinze, W.J. (Eds). Vol. 156, Geological Society of America, Boulder, Colorado. 15. Davis, D.W. and Paces, J.B. (1990) Earth Planet. Sci. Let. 97 (1-2), 54. 16. Reidel, S.P., Johnson, V.G. and Spane, F.A. (2002). Natural Gas Storage in Basalt Aquifers of the Columbia Basin, Pacific Northwest USA.A Guide to Site Characterization. PNNL-1396), Pacific Northwest National Laboratory, Richland, Washington. 17. Sass, B.M., Engelhard, M.H., Bergman, P. and Byrer, C. (2001). In: First National Conference on Carbon Sequestration. Washington, D.C., National Energy Technology Laboratory.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) Published by Elsevier Science Ltd

1641

EVALUATION OF CO2 SEQUESTRATION IN SALINE FORMATIONS BASED ON GEOCHEMICAL EXPERIMENTS AND MODELING Bruce M. Sass 1, Neeraj Gupta 1, Sandip Chattopadhyay 1, Jennifer Ickes 1, and Charles W. Byrer 2 1Battelle, Columbus, Ohio, USA; 614-424-6315; [email protected] 2National Energy Technology Laboratory, Morgantown, WV, USA

ABSTRACT

This paper presents results of a recently completed study in collaboration with the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) to conduct research on the feasibility of CO2 sequestration in deep saline formations. The objectives of the study were to: (1) investigate the potential for long-term sequestration of CO2 in a deep, regional host rock formation; and (2) evaluate the compatibility of overlying caprock with injected CO2 with regard.to its effectiveness as a barrier against upward migration of the injectate. Experiments were conducted using rock samples from different potential host formations and overlying caprocks, as well as certain pure mineral specimens to evaluate specific mineral reactions. Reaction vessels containing a pure solid phase or mechanical mixture of phases, and liquid were pressurized with CO2 or a mixture of either N2 and CO2, or N2, CO2, and SO2. The duration of the experiments was one to three months at pressures consistent with deep reservoirs, and temperatures of either 50°C (typical) or 150°C (elevated). It was concluded from the experiments and geochemical modeling calculations that the potential for adverse effects of CO2 injection into capped, sandstone formations is low.

INTRODUCTION

The overall objective of this geochemical study was to enhance understanding of the interactions between injected CO2, formation fluids, and rock media based on laboratory experiments and geochemical simulations. Once injected into reservoirs, a large portion of the CO2 may remain as a separate phase and float towards the top of the reservoir due to density contrasts, while some may dissolve in the formation fluid. The dissolved CO2 can react with formation minerals and, under certain conditions, cause precipitation of mineral phases resulting in mineralogical sequestration or permanent trapping of carbon. It is important to understand both the short-term reactions that may affect injectivity during the injection facilities operation and the longer-term reactions that may determine the ultimate fate of injected CO2. The effect of SO2 impurity in the CO2 stream was also investigated. Geologic disposal of CO2 involves finding geologically suitable formations for sequestering large amounts of CO2 for a long period without significant environmental risk, and at a reasonable cost. Suitable formations are deep, regionally extensive, filled with saline waters, and separated from freshwater aquifers and other formations of economic interest by low permeability caprock. For CO2 disposal applications, a minimum depth of about 800 meters is required to maintain the pressure for retaining CO2 in a dense, supercritical fluid phase. Other site-selection criteria are based on suitable geologic, hydrogeologic, geochemical, and seismic parameters. Because there is a significant overlap in the presence of CO2 emission sources and potential reservoirs for geologic sequestration, the focus of current investigations is on the midwestern and Ohio River Valley regions of the United States. However, due to the fundamental nature of the geochemical

1642 experiments the findings are also applicable to other similar reservoirs. Rock core samples were obtained from six locations that included the Eau Claire, Rome, and Mt. Simon formations, representing formations that could be in immediate contact with injected CO2 if a sequestration facility were operated in the region. The Mt. Simon is generally a fine, to coarse-grained quartz and feldspar sandstone. The formation has a relatively large volume of primary intergranular pore space with lesser amounts of secondary pore space. Minor amounts of detrital and authigenic clay may limit porosity, and a small amount of dolomite cementation may be present. Clay in the formation appears to be mostly glauconite, illite or chlorite. The Eau Claire is a formation with variable lithology. Lower portions often are similar to the Mt. Simon sandstone, especially in Illinois, while upper portions often are shale, dolomite, or siltstone. The dolomitic portions have low porosity and are well cemented with calcite and dolomite cement. Core samples from Ohio that were used in this study were provided by the Ohio Geological Survey. CO2 injection potential at two locations in this formation and the overall economic and implementation issues are discussed in Gupta et al. [ 1, 2]. In addition to the rock cores, commercially available specimens of anorthite, glauconite, kaolinite and montmorillonite samples were also tested. Results of detailed analyzes and compositions of all samples used in the study are presented elsewhere [3].

EXPERIMENTAL Experiments were conducted using rock samples that represent different potential host reservoirs and overlying rocks. Variations in temperature and time were explored, to the extent feasible, because they affect the rate and extent of reaction, respectively, which could have important ramifications for a full-scale injection operation. For example, if the reactions are too slow, the potential for leakage of CO2 into overlying formations may increase. On the other hand, fast reaction rates may adversely affect the porosity and permeability of a formation near the injection well by reducing injectivity and therefore shortening the lifetime of the injection well. Variations in pressure also were explored because pressure controls the concentration of CO2 in the brine and therefore the amount available for reaction. Experiments also were conducted to test the effects of SO2 impurity. Tests were performed using typical concentrations of SO2 found in flue gas from coal combustion when desulfurization is not used. After the experiments were completed, detailed characterization was performed to determine if SO2 impedes carbon sequestration or produces byproducts that may potentially impact the sequestration process. Additionally, the mineral pyrite (FeS:) was added to some experiment mixtures to maintain a chemically reducing environment and to provide a source of iron. In this capacity, it was thought than iron carbonate minerals might be formed by reaction of pyrite with CO2. Pyrite occurs naturally in some parts of the Mt. Simon formation. Experiments were conducted in l-liter pressure vessels designed so that they could be filled with a mixture of a brine solution and solid material, then pressurized with CO2, and equilibrated at constant temperature and pressure. The pressure vessels were made of chemically resistant HasteloyTM C-276 and lined with PTFE-Teflon inserts. The experiments ran for a period ranging from 30 to 90 days. At the end of the reaction period, a small sample of gas was collected in a Tedlar bag and analyzed by GC/FID for CO2, 02, N2, and SO2. The solid and solution phases were separated by decanting the fluid into a capture vessel. Constant pressure during the transfer was maintained to avoid inducing precipitation while the fluid was being transferred. A 2-~tm-pore size frit at the base of the tube inside the reactor prevented carryover of solids into the capture vessel, where the liquid was cooled by a water jacket. After the contents in the capture vessel were cool, the solution was analyzed for total organic carbon, alkalinity, pH, ORP, sulfate, chloride, and metals. The solids were rinsed two times with approximately 100 mL of deionized water that had been adjusted with NaOH so it has a pH between 8 and 9. The pH of the water was adjusted so that any carbonate compound that might have formed would not be dissolved by naturally acid deionized water dried and analyzed in the same manner as the unreacted samples for comparison. TM

Solid samples were analyzed by several different techniques, including optical microscopy, x-ray diffraction

1643 (XRD), scanning electron microscopy (SEM) with energy dispersive spectroscopy (EDS), and x-ray photoelectron spectroscopy (XPS). XRD was performed using a Rigaku Geigerflex X-ray Diffractometer with Cu Ka x-ray radiation. A JEOL 840 SEM was used to collect images. A Physical Electronics Quantum 2000 xPS System was used to collect XPS spectra. The Quantum 2000 XPS was operated at the William R. Wiley Environmental Molecular Sciences Laboratory at Pacific Northwest National Laboratory, in Richland, Washington.

RESULTS Results of experiments with Mt. Simon sandstone indicated congruent leaching of quartz and feldspars into the solution phase. However, no mineral precipitates were found in the products despite use of advanced characterization tools. Eau Claire shale, a potential confining layer, exhibited very little leaching. This shale contains a phosphate-bearing mineral (hydroxylapatite), which is an indicator of bulk dissolution. Low dissolution behavior suggests, from a geochemical perspective, that Eau Claire shale has good suitability as a caprock. Throughout these experiments there were no indications of carbon mineral trapping reactions (i.e., precipitation of carbonates). Mineral trapping can occur only if the reservoir supplies needed divalent elements such as calcium, ferrous iron, and manganese. The Mt. Simon has a limited amount of iron in glauconite that occurs in some locations; however, the short-term experiments conducted during the current project did not show any indication of mineral trapping of CO2 in this formation. Results of the 30 to 90 day tests show no behavior that would adversely affect injectivity. This is encouraging for potential future injection facilities that need to maintain performance over a period of years or decades. However, anhydrite (or gypsum) is a potential mineral precipitate that should be considered before injecting CO2, because of possible injectivity loss due to pore clogging. Any additional calcium supplied by dissolving mineral phases (e.g. dolomite) could force precipitation of gypsum. Anhydrite formed in one test where the sulfate level in the brine was artificially elevated. A small amount of SO2 co-mixed with CO2 increased iron leachability in all samples tested, but had no other effect that could be determined. The potential benefits of co-injecting SO2/CO2 mixed waste could be considered to determine whether this practice is economically favorable.

Geochemical Modeling Geochemical modeling was used to calculate equilibrium concentrations of chemical species in solution and determine the relative saturation of solid phases in equilibrium with a solution. Computer modeling codes were used to simulate interactions between minerals, brine, and CO2/SO2 atmosphere. Three geochemical codes were used in this study, as appropriate for the temperature and ionic strength under consideration. They included PHRQPITZ [4] and The Geochemist's WorkbenchT M [5], which are capable of performing calculations in high salinity conditions. In addition, PHREEQC [6] was used because of its extensive mineralogical database, but was limited to low salinity simulations. The selected rock/mineral and CO2 interactions for the simulations included anorthite, annite (proxy for glauconite [7]), and dolomite. Each of the simulation runs were conducted at three different temperatures: 25°C, 50°C, and 150°C. With increasing amount of CO2 consumed, the reactant materials dissolve into the formation water, which eventually can lead to precipitation of product phases. Once formed, product phases remain in equilibrium with the solution unless they completely react out. The simulation runs terminated when equilibrium had been achieved or when all of the reactant phases had been consumed. It was concluded that anorthite and annite (glauconite) are potential reactants for CO2 in deep formations, where they can form calcite and siderite, respectively. Although precipitation of carbonate minerals is favorable to long-term storage of injected CO2, it was apparent from the experimental studies that significant transformations would require long time periods to take place. In contrast to the slow kinetics of silicate

1644 minerals, reaction rates for carbonates and sulfates are more rapid. The simulations predicted that dolomite dissolves to a greater extent than gypsum precipitates, as CO2 was added to the system, implying that net porosity would likely increase.

CONCLUSIONS

The overarching conclusion of the experiments and computer simulations is that no adverse effects of CO2 injection into Mt. Simon sandstone (host rock) would likely occur over a short-term period (decades). Rock samples that are predominately composed of quartz sand were relatively unchanged by interaction with the CO2. Experiments with samples that contain appreciable amounts of potassium feldspar showed significant dissolution, but no precipitation byproducts. Similarly, dolomite was degraded by CO2-rich brine, resulting in higher levels of calcium, magnesium, and bicarbonate in solution. As a consequence, it appears that gypsum can precipitate when sulfate levels in the brine are very high. However, modeling calculations revealed the volume of dolomite that dissolved was greater than the volume of gypsum precipitated. Therefore, a net porosity increase is expected, which could result in an increase in permeability. Experiments to verify mineral trapping (i.e., conversion of CO2 to a carbonate mineral) showed progress toward that end, but generally were too slow to be completed during short time periods ( 1, since heterogeneity has mitigated buoyancy effects. Careful consideration of the capacity factor quoted by other authors [7, 8] indicates that much of the perceived discrepancies can be attributed to different conventions for defining capacity factor. For example, Pruess et al. [7] use a one-dimensional radial flow model with homogeneous properties and report Ci values in the range of 0.2 to 0.4. In contrast, van der Meer [8] considers gravity and a dipping formation and applies a rough heterogeneity correction, yielding the much smaller values of CiCgCh = 0.01 to 0.07. The difference implies CgCh- 0.1, which is near the lower end of the range encountered in our studies.

SIMULATION RESULTS The present modeling studies focus on CO2 injection into a sedimentary formation at a depth of 2,000 m formed by fluvial processes that created strong permeability heterogeneity. The top and bottom boundaries of the model are closed, to represent sealing shale layers, and the lateral boundaries are open, to approximate a laterally extensive formation. CO2 injection takes place at a constant rate through a central well that penetrates the lower half of the 100-m thick model. The simulation shows that CO2 preferentially flows through high-permeability features such as barrier bars, sand channels, splays, and washovers, while avoiding low-permeability flood-plain shale layers (Figure 2). Most shale layers are discontinuous, however, and buoyancy flow is strong, making the interplay between buoyancy flow and formation heterogeneity a key factor in determining the distribution of CO2 in the subsurface, which in turn has important ramifications for the capacity factor. After injection of CO2 ceases, the subsurface distribution of CO2 continues to evolve, primarily driven by buoyancy flow of the gas-like phase out the lateral boundaries of the model. In general, the relative importance of sequestration in the aqueous phase by dissolution can be large if imperfect cap or lateral seals allow the loss of gas-like CO2.

1647 1 year

CrY2

SIXI

P/Pco2

0.07 O.OD 0.0~ I~. 0.04 0.03 i

. i

-.~.;;-.-.....+ ...........................~........................... -"~" ...... 2 :

O.m .............. °°°o

""-'"--"4"-"................ ~ . . . . . . . . . . . . + . . . . . . . . . . 1o

2o

3o

~ ............ 4o

~ .......... 6o

oo

1im,(~

Figure 2" Simulation results for spatial distributions of injected C02 near the beginning (left column) and end (center column) of the 20-year injection period, and after a subsequent 40year recovery period (fight column). CO2 exists in a gas-like phase (top row) and dissolved in the aqueous phase (middle row). The capacity factor (bottom row) provides an integrated, quantitative measure of the fraction of the subsurface being used for sequestration. The space and time domains used to define capacity factor must be chosen carefully to obtain meaningful results. When there is a particular volume associated with the sequestration scenario under consideration (e.g., an isolated fault block, an anticline trapping structure, a volume of the subsurface available to the operator), this is the natural spatial domain to use. In contrast, for a laterally extensive formation with no natural geological boundaries, there is no unique choice for the volume on which to base the capacity factor. In Figure 2, the capacity factor averaging volume is taken to be constant, and to consist of the entire model volume. This choice results in a rapidly increasing C at early times, before CO2 reaches the outer edge of the model, and a gradually decreasing C at late times, after CO2 injection has ceased and buoyant gas-like CO2 escapes out the sides of the model. The strong time dependence of C makes it difficult to choose a single value of C to characterize the sequestration process. One possible alternative formulation is to define a dynamic capacity factor that makes use of the self-similar nature of the Buckley-Leverett solution for the propagation of the CO2 front away from the injection well. As time t increases, the volume V for which capacity factor is calculated also increases, in accordance with a fixed value of V/t. Figure 3 compares C versus t for dynamic (fixed V/t) and conventional (fixed V) capacity formulations. In both cases, for the recovery period (20-60 years), V remains fixed at the value used at the end of the injection period. For the 1 km by 1 km model, the conventional C versus t curve shares the shortcomings of the C versus t curve shown in Figure 2. For a laterally infinite model, the conventional capacity factor (using the same averaging volume as the finite model) does not characterize the entire CO2 plume, only the central part of it. Choosing a larger averaging volume would delay the time at which the CO2 plume outgrows the averaging volume, but not solve the fundamental problem. In contrast, the dynamic capacity factor characterizes a volume that grows along with the CO2 plume.

1648

O'lf''"

':" " ' 1 krr~by 1'i~ ~ ' . ~wentional'capad~ (r :'5()0 m)' ! o Infinitemodel- conventional ca~adty (r = 500 m) ,_ 0.08 .........m m ..!n!initemqdel-.dyn~c ~..ty..(r2/t =.146m2!day)........ t~ LL

.~006 ¢o t~ a.

0

0.04

I-- 0.02 10

20

30

40

50

60

T i m e (yr)

Comparison of dynamic capacity factor, which uses a fixed value of V/t for averaging, and conventional capacity factor, which uses a fixed volume V. For these uniform-thickness models, volume is proportional to the square of radial distance.

F i g u r e 3:

ACKNOWLEDGEMENTS

We thank C. Oldenburg and K. Karasaki for their critical reviews. This work is part of the GEO-SEQ project, which is supported by the U.S. Department of Energy through the National Energy Technology Laboratory (NETL) under Contract No. DE-AC03-76SF00098.

REFERENCES 1. Pruess, K., Oldenburg, C., and Moridis, G. (1999). Rep. LBNL-43134, Lawrence Berkeley National Laboratory, Berkeley, CA. 2. Pruess, K. and Garcia, J. (2002). Environmental Geology, 42, 282-295. 3. Xu, T., Apps, J.A., and Pruess, K. (2002). Rep. LBNL-50089, Lawrence Berkeley National Laboratory, Berkeley, CA. 4. Hovorka, S.D., Doughty, C., Knox, P.R., Green, C.T., Pruess, K., and Benson, S.M. (2001). Evaluation of brine-bearing sands of the Frio formation, upper Texas gulf coast for geological sequestration of CO2, First National Conference on Carbon Sequestration, May 14-17, Washington DC, National Energy Technology Laboratory. 5. Doughty, C., Pruess, K., Benson, S.M., Hovorka, S.D., Knox, P.R., and Green, C.T. (2001). Capacity Investigation of Brine-Bearing Sands of the Frio Formation for Geologic Sequestration of CO2, First National Conference on Carbon Sequestration, May 14-17, Washington DC, National Energy Technology Laboratory. 6. Buckley, S.E. and Leverett, M.C. (1942). Trans. Am. lnst. Min. Metall. Eng., 146, 107-116. 7. Pruess, K., T. Xu, J. Apps, and J. Garcia. (2001). Numerical modeling of aquifer disposal of CO2, Society of Petroleum Engineers, SPE/EPA/DOE Exploration and Production Environmental Conference, San Antonio, TX, 26-28 February. 8. van der Meer, L.G.H.. (1995). Energy Conservation and Management, 36, 6-9, 513-518.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1649

COST COMPARISON AMONG CONCEPTS OF INJECTION FOR CO2 OFFSHORE UNDERGROUND SEQUESTRATION ENVISAGED IN JAPAN Hironori Kotsubo 1, Takashi Ohsumi l, Hitoshi Koide 1, Motoo Uno Takeshi Ito 2, Toshio Kobayashi 3 and Kozo Ishida 3 l Research Institute of Innovative Technology for the Earth (RITE) 9-2, Kizugawadai, Kizu-cho, Soraku-gun, Kyoto, 619-0292, JAPAN 2 SK Engineering Co., Ltd. 3 Japan Drilling Co., Ltd.

ABSTRACT

In connection with CO2 sequestration into offshore aquifers, one of the basic considerations is how the CO2 can be brought economically from the coast to the intended geological formations. Here, RITE, in cooperation with oil industry experts, implemented a preliminary study in which several possible methods were assessed using CAPEX and OPEX, with demolition costs included. Although which method is superior varies, depending on geological, geographical, environmental and several other conditions applicable to each specific project, the outcome of the study explicitly indicates that "extended reach drilling (ERD) from onshore" and "subsea completion" are worth considering when those hypothetical parameters employed in the study are applicable.

INTRODUCTION

At present, Japan is in the process of 5-year R&D program of underground storage of CO2 [ 1], and this study was carried out as part of this program. Offshore saline aquifers are the target geological formation in this program because (1) most of large-scale emission sources of CO2 are located near the coast in Japan, (2) aquifers of large volume are expected to be found more in offshore than on land, and (3) site acquisition is much more costly on land. At present, we assume the total time scheme of the sequestration process as shown in Figure 1, which is based on practical results from similar processes such as large-scale underground storage of natural gas in aquifers [2]. The total system of underground sequestration can be roughly divided into three processes: recovery, transportation, and injection. While quite a few papers regarding the former two categories are publicly available, this does not seem to be the case with the latter. Although the methods of recovery and transportation have been well studied, the injection process has not been established as it is significantly affected by geographic, geological and topographic features of the site. We think that the cost of injection into an offshore aquifer varies with the method applied. One reason is that there are a variety of applicable designs and construction methods of wells and surface facilities (especially offshore) that depend on the conditions of injection site. The other reason is that there are many uncertainties in exploration and operation, as is the case with petroleum development. There are a few works [3, 4] dealing with costs of offshore aquifer storage in several countries, but in Japan, these are few. We have

1650 studied the cost of conditions and stages of injection processes in a Japanese context. This paper shows the results of our preliminary analysis on the costs of injection facilities. FRAME OF E S T I M A T I O N

Configuration of Wells and Wellheads When we think of injecting recovered CO2 into coastal offshore aquifers in Japan, there may be three types of configuration of injection facilities, i.e. wells and wellheads, as shown in Figure 2. They are roughly categorized by location of wellheads.

(A) Extended Reach Drilling (ERD)from onshore The wellhead is situated onshore, near a CO2 source. Wells are drilled underground to a target reservoir by a directional drilling path, similar to the horizontal well drilling method. ERD has been in practical use since the late 1980s and there are a many applications recorded in the petroleum industry. The world's longest ERD deviation length is about 10 km.

(B) Subsea completion The wellhead is installed on the seabed and is connected to a CO2 source by submarine pipeline. Wells are drilled offshore above a target reservoir. Standard Jack-up drilling rigs are applicable in water depth of less than 100 m and semi-submersible drilling rigs are usually used in deeper water.

(C) Offshore platform This case seems most familiar. The wellhead is installed on a fixed platform constructed offshore above a target reservoir. In the area of water depth of less than 1O0 m, the most cost-effective platforms are thought to be of the simple wellhead supporting type, whose wells are drilled with Jack-up figs. In deeper water, platforms equipped with drilling units are thought to be the most economical.

Preconditions and Assumptions for Estimation For cost comparison, it is assumed that large-scale underground storage, such as applicable to a coal-fired power plant of 1000 MW class, and nine cases are set, as shown in Table 1, under preconditions as follows: Injection rate: Total amount of injection: Number of injection wells:

10 Kt-CO2/day 73 Mt-CO2 (Period of injection: 20 year) Case 1: One horizontal well with 2 km perforation Other cases: Two horizontal wells with 1 km perforation

Capital Expenditure (CAPEX), Operating Expenditure (OPEX) and the cost for decommissioning were estimated for each case. The contingency cost was also calculated considering that additional injection wells may be needed in case of problems. In each case, compressors for transportation are to be installed onshore next to the CO2 source. CAPEX and OPEX for compressors are not included in this cost estimation. RESULTS AND DISCUSSIONS Figure 3 shows the result of estimation. 1) Of the cases where source-reservoir distance is 10 km, "ERD from onshore" is the least expensive in both the total cost and the segmental costs of CAPEX, OPEX and decommissioning. Additional CAPEX for Contingency is comparably larger than other cases, but its proportion is small in the total cost. 2) Except for "ERD from onshore", "subsea completion" is economically superior to "offshore platform" in each conditions, i.e. "subsea completion with Jack-up Rig" is less expensive than "offshore platform with Jack-up Rig" at 90 m water depth and "subsea completion with Semisubmersible Rig" is less expensive than "offshore platform with installed Rig" at 150 m water depth. 3) In the cases of "subsea completion", the difference of applicable methods that comes from water depth gives very small differences to estimated total costs, i.e. the estimated total costs for "subsea completion with Jack-up Rig" and "subsea completion with Semi-submersible Rig" are nearly the same. 4) In the cases of "offshore platform", water depth seems to matter because the difference of applicable

1651 methods gives rather large differences to estimated total costs. Some implications can be derived from above results: 1) If there is a suitable reservoir within 10 km form a CO2 source and if it is applicable of "ERD from onshore" method, the method is economically superior to other options. 2) For other cases, "subsea completion" would be the second best option from the viewpoint of cost. But we should take account of the following points in the future estimation study: 1) Degrees of technical difficulty that lie in ERD and subsea completion are not considered in this estimation. Those methods are still improving and we should evaluate their progress and limitation. 2) If monitoring wells were required for safety reasons, design concept for wells and wellheads configuration might be totally changed. We would also like to analyse the costs for exploration and monitoring to enrich basic data for the economic model that is under development [5] to estimate the total costs of CO2 sequestration in Japan.

mcess

R ecovery

Tin hg

Transportation

h)ctbn

I

" Bibliographic Research • Geological Survey

Expbrati)n

• Exploratory Drilling

More

than 10 years C onstmctbn

• Plant Construction

0 peratbn

• Recovery • Maintenance

years

1 year

D ecom m i s s b n J n g

i

.,~.~.~}i~;. e

-,

• Construction of Injection and Monitoring Facilities

• Pipelining

~~ 20 to 40

1

• Injection • Monitoring • Maintenance

• Transportation • Maintenance

.

• Well Decommissioning

• Dismantlement

• Plant Demolition

•

J

,. • M o n i t o r i n g ?

P o s t 0 peratbn

/ ]

Figure 1: Time scheme of sequestration business

~ ) ERD f ~ m onshore

poht soume ofC 0 2 0 cean _ _ _ _

I

. _ _

1

_ _ _ L

___L_.

A quffer reservoir

~ ) S u b s e a corn p l e t b n

Submarhepipeline

) 0 ffshore phffom

~

~

~

7 o~ho~ phtfom

Figure 2: Three categories of well and wellhead configuration

1652

TABLE 1 NINE CASES FOR ESTIMATION

Case 1

Locatbn ofWelhead

Method ofWellDrfllhg

Water Depth

Onshore

ERD fromonshore

90m

1090m

With Jack-up Rig

90m

I090m

With Semi-submersible Rig

150 m

1150 rn

With Jack-up Rig

90m

1090m

With Rig installed on the Ratform

150m

1150m

Case 2 Case 3 Case 4 Case 5

Subsea On a Offshore Fixed Ratform

Case 2' Case 3' Case 4' Case 5'

Subsea On a O ~ e Fixed Ratform

Reservor Depth

With Jack-up Rig

90m

1090m

With Seni-submersible Rig

150m

1150m

With Jack-up Rig

90m

1090m

With Rig installed on the Ratform

150m

1150m

Source-Reservor Distance

10 km

50 km

~illi3n ¥] 0 Case Case Case Case Case

1 2 3 4 5

Case Case Case Case

2' 3' 4' 5' 0

5

I0

15

20

25

30

35

70

140

205

275

345

410

[¥/t--C 0 z] 480

ICAPEX

NOPEX

IDecomm issioning

.'.';Contingency-i

F i g u r e 3: Results of estimation

ACKNOWLEDGEMENT This study was supported by the Ministry of Economy, Trade and Industry (METI) of Japan and New Energy and Industry Technology Development Organization (NEDO).

REFERENCES 1.

Koide, H., Ohsumi, T., Uno, M., Matsuo, S., Watanabe, T. and Hongo, S. (2002). In: Proceedings of

2. 3.

Gaz de France (1997). Safe, Environmentally Sound Underground Storage Solutions. Hendriks, C.A, Wildenborg, A.F.B., Blok, K., Floris, F. and van Wees, J.D. (2001). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 967-972, Williams, D., Dude, B., McMullan, P., Paulson, C. and Smith, A. (Eds). CSIRO. Allinson, G. and Nguyen, V. (2001). In: Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies, pp. 979-984, Williams, D., Durie, B., McMullan, P., Paulson, C. and Smith, A. (Eds). CSIRO. Akimoto, K., Kotsubo, H., Asami, T., Li, X., Uno, M., Tomoda, T. and Ohsumi, T. (2002). In:

the Sixth International Conference on Greenhouse Gas Control Technologies.

4.

5.

Proceedings of the Sixth International Conference on Greenhouse Gas Control Technologies.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1653

R A T E OF D I S S O L U T I O N D U E TO C O N V E C T I V E M I X I N G IN THE U N D E R G R O U N D S T O R A G E OF CARBON DIOXIDE

J. Ennis-King and L. Paterson Australian Petroleum Cooperative Research Centre CSIRO Petroleum, P.O. Box 3000, Glen Waverley VIC 3150 Australia

ABSTRACT In a typical underground storage project, a proportion of the injected gas will form a layer beneath the caprock due to buoyancy. The saturation of underlying brine with dissolved CO2 creates a density instability, and on long time scales this causes convective mixing, greatly increasing the overall rate of dissolution compared to a purely diffusive mechanism. Two time scales of interest are tc, the time at which the instability occurs, and tmix, the time at which the overlying layer of free CO2 is completely dissolved. Analytical estimates of these time scales are given, and for typical conditions it is shown that t¢ - 1 to 100 years, while tmix "" 10,000 to 100,000 years, so that t¢ 0, and there is a no flux boundary condition on C at z=H. This is mathematically equivalent to the well-studied problem of temperature-driven convection in a porous medium [2]. One could include the effects of temperature as well as concentration, since the usual geothermal gradient makes the formation water less dense with depth and so is destabilising, but for most geological storage scenarios, the temperature effects are weak and sub-critical (i.e. these effects alone will not cause mixing) and so they will be ignored here. The usual stability analysis (based on the temperature analogue) assumes a linear vertical profile of concentration across the formation, and shows that this profile is unstable to small perturbations when the dimensionless Rayleigh-Darcy number Raz,= g K Ap H/(,uqkD) exceeds a critical value. Here Ap=/3cCs,,tpo is the density increase due to the dissolved CO2. For these boundary conditions, the critical value of Rat, is 27.10 [2]. This type of analysis has previously been applied to underground storage of carbon dioxide, and it was shown that convective mixing should occur in most cases [3]. However the problem is clearly a transient one, since the equilibrium state would be C=Gat throughout the layer, and the concentration profile prior to instability is not linear but rather a diffusive front. At short times (large H), the profile is C=Csaterfc(z/(2 (D t) 1/2 )), where erfc is the complementary error function. An approximate analysis of the transient problem was given by Elder [4], and detailed analysis by Caltagirone [5]. The scaling

1655 can be obtained by the following argument. Prior to the instability, the concentration across the layer of dissolved gas varies from Csat to 0, which is roughly analogous to the situation of the linear concentration profile (it is possible to take account of the nonlinear profile [2], but the scaling is unaltered). Thus one uses the above stability analysis, but replaces the total formation thickness H with the layer thickness (D t)z/2. The result is that the critical time t~ at which the instability begins to propagate is tieD t c ~ c o (Ap)2g2K 2

(3)

where co is a numerical constant. Published numerical results [5] give a lower bound for the critical time, and indicate that Co is in the range 80-100. The critical wavelength 2c of the most unstable fluctuations is of the order of the layer thickness at instability, so 2c .~ ct/.t~ D/(g K Ap). Fitting again to published results gives Cl in the range 100-120. Note that the formation thickness H does not appear in these formulae, since the argument assumes that Rao significantly exceeds the critical value i.e. that convection occurs at some saturated layer thickness much less than H. The assumption of isotropic permeability K can be relaxed, allowing for vertical and horizontal permeabilities kv and kh respectively, and the corresponding formula can be obtained by replacing K with 4kvkh/((kv)l/2+(kh)ln) 2 (assuming that the result for the linear concentration profile [2] can be carried over to this case). For k~/kh oling ',e

point

Fig. 1 High pressure cell

E X P E R I M E N T RESULTS AND DISCUSSIONS

Temperature distribution in COz hydrate grows up Figure 2 shows the temperature change at each height of the cell with regard to the formation of CO2 hydrate observed, when CO2 was pressurized from the lower entrance. The pressure was 2.5MPa and the total amount of gas discharged was 350ml/min. It is shown from Figure 2 that the temperature increased soonest at the 23 cm position, and at every 220 minutes elapsed time. CO2 hydrate started to form at this position. The temperature in the entire cell increased after a few minutes. Hydrate growth was found at the base, increasing upwards, and the temperature distribution showed that rapid growth was also found from about 27cm.

1673 It was observed that there were two parts to the temperature increase in the overall domain. The first part was due to heat conduction from the formation point, and another part was around the cell base, by the growth of the hydrate above. The inclination of the isothermal curves during the hydrate growth shows the rate of growth was about 0.5crn/minutes, as shown in Figure 2.

210

220

230

Temp :~,

240

250

Time

f ;00-0.5 D0.5-1

260

270

(sin)

[ 3 1 - 1 . 5 111.5-2 1 1 2 - 2 . 5 1 2 . 5 - 3

1 1 4 - 4 . 5 1 4 .5-5 1 5 - 5 . 5

15.5-6

16-6.5

1 1 3 - 3 . 5 11 3 . 5 - 4 i

1 6 .5-7 1 7 - 7 . 5

Figure 2: The change with the lapse of time of height direction temperature distribution in center Dart of cell of CO~ hydrate

Amount of gas consumption when COz hydrate grows upwards The speed of growth when the CO2 hydrate grew was examined from the amount of the gas consumption. The theoretical chemical amount of CO2 hydrate is as shown in the next expression. CO2(gas)+8.13H20(liquid) ~ CO2 • 8.13H20(hydrate) ......... (1) The hydrate number 8.13 in the expression is the value that the authors obtained through experimentation. Moreover, the speed of hydrate growth is expressed, in general, by the following expression, including diffusion and adsorption. dng =KOC_feq)nw (2) dt Here, ng is a mole of CO2 molecules intake the hydrate, nw is a mole of water, f is fugacity of the gas under experimental conditions, feq is the fugacity of the gas in three-phase equilibrium pressure. K is reaction rate constant and it has the dimension of (mol • MPa 1 • minl). Empirical formula concerning the amount of consumption of COz per mole of water is derived as follows. Here, the empirical formula, when growing up, becomes the next expression if corrected by the amount of the gas absorption to the formation point. ng = 1 _ [ 1 _exp{_HnKOC_f~q)t}]+ ngf ..... (3) nw,O Hn nw,O Here, nw o are moles of initial water, ng/" is a mole of CO2 that had dissolved in water at the time of formation. Hn shows the hydrate number of only when growing up. Hn shows as follows. Hn=COJ(q l-q2)H20 (4) ql; mole of CO2, which enters one water mole after hydrate is completed. qe; mole of CO2, which enters one water mole at the time of formation. The reaction rate constant K was determined by using the experiment data for the calculation type concerning the amount of the gas consumed in the CO2 hydrate growth. Calculated and experimental

1674 results are compared is in Figure 3. The amount of gas consumption almost agrees with the calculated value; the speed of gas consumption is fast when values of K are large, by high pressure, as shown in Figure 3. When the CO2 hydrate grew upwards because of these conditions, the level of gas consumption showed a tendency (that increased under the experimental conditions) for the gas-water contact area to increase. From these results, the level of gas consumption during the experiment almost corresponded to the calculated value, by which the fugacity difference was assumed to be the driving power. 0.07

• •

L_ ~"

3.5M P a 0.06

"

..

~ °

3.0M P a . .

/

.--

/

.-/... ..-

lI°' o to

¢0

-° "

~

0.03

experin

ental

ca]cuhted

(.)

0.02

.

0

.

.

20

.

.

.

40 Ti~e

.

.

60

.

80

100

~h)

Rg. 3 Hydrate formation kinetics of CO2 (Injection point 0cm, flow rate 350ml/min) SUMMARY

The formation and growth of CO2 hydrate was observed in a model sediment with porous media and solutions saturated with gases. From the experiment and discussion, the following conclusions were obtained. The appearance and the process of growth clearly shows the hydrate growth, in which the temperature distribution can be displayed. The growth rate of CO2 hydrate upwards ranged 0.5-1.0cm/min under the experimental conditions used. When the CO2 hydrate increased because of these, the amount of gas consumption showed the tendency, that increased under the experimental conditions, for the gas-water contact area grows. Moreover, the level of gas consumption during the experiment was almost corresponded to the calculated value, by which the fugacity difference was assumed to be the driving power. In future work, it is intended to obtain fundamental data of CO2 hydrate kinetics, especially on the dissociation process of hydrate, the difference of time growth with vertical and horizontal growth direction. The research results can be used to achieve the CO2 utilization for methane hydrate development. REFERENCE Sloan,E,D,Jr. (1998) Clathrate Hydrate of Nattural Gasea. 2nd edit. pp.586-601. Marcel-Dekker, New York.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1675

M E A S U R E M E N T S OF CO2 SOLUTION DENSITY UNDER DEEP OCEAN AND UNDERGROUND CONDITIONS M. Nishiol, y. Song2 and B. Chen 2 1National Institute of Advanced Industrial Science and Technology (AIST) 1-2-1 Namiki, Tsukuba-shi, Ibaraki 305-8564, Japan 2Research Institute of Innovative Technology for the Earth (RITE), AIST-Tsukuba Branch

ABSTRACT

The increase levels of CO2 emitted from fossil fuel consumption is one of the largest factors to increase the seriousness of global warming. In order to mitigate this huge amount of CO2 from the atmosphere, proposals for ocean sequestration and geological storage of CO2 have been investigated theoretically and experimentally for the past ten years. With emphases on a fundamental and engineering technical study associated with this technology, the understanding of physico-chemical properties of a pure/salt water-carbon dioxide system at high pressure and wide range of temperatures is also necessary as the basic database. The carbon dioxide pure/salt water solution density is one of the key physical properties and is a critical property for estimating numerically the dynamic evolution of carbon dioxide enriched pure/salt water plume. In this study, we report measurement data on carbon dioxide pure/salt water solution density, obtained using the Magnetic Suspension Balance (MSB) system and the Mach-Zehnder (M-Z) interferometry method.

INTRODUCTION

For the last two decades, the impact of increasing concentration of greenhouse gases, particularly CO2, on the earth's atmosphere has become a subject of intense scientific and engineering investigations. Several technologies were proposed for limiting CO2 emissions and mitigating CO2 concentration from atmosphere. From among these, CO2 ocean/geological sequestration was considered to be one of the acceptable options [ 1,2,3]. Part of the work of this project included a study of chemical and physical parameters measurement, and here, we report the results from the last investigations into the density of CO2 dissolved water solution. For either academic investigation or engineering application, the fundamental physical/chemical properties of pure/salt water and carbon dioxide systems at high pressure and low-high temperatures, from the point of environmental impact and technology development, are critical. In this study, the carbon dioxide pure/salt water solution density is measured by using the Magnetic Suspension Balance (MSB) method and the Mach-Zehnder Interferometry(M-Z) method. As a physical property, CO2 water solution density had drawn the attention of Haugan and Drange [4] ten years ago, when they investigated the sinking of CO2 enriched seawater. They conservatively and theoretically estimated the change in CO2 solution seawater density due to change in carbon concentration (mol/m 3) to be 8.0x10 3 kg/mol (about 0.182 g/cm3). Ohsumi [5] obtained the first set of experimental data. He applied the vibrating-type densitometer to a CO2-water solution system and measured the solution density at lower CO2 concentration (less than 1%). For a high concentration case, Aya [6] measured the density change by detecting the pressure drop due to CO2 dissolving into fresh water. Very recently, Song [7,8] reported a set of experimental date of CO2-water and CO2-seawater solution density measured systematically by leaser interferometry with the concentration almost approaching to the solubility. With the

1676 focus on ocean sequestration and geological storage, the density change of CO2 water solution is investigated in this study. The experiment was carried out at temperature of 293°K, pressure from 5 to 20 MPa, and concentration up to 0.045.

EXPERIMENTAL APPARATUS AND PROCEDURE

Magnetic Suspension Balance (MSB) system Wagner [9] developed the fluid density measurement method using the MSB system. We used the FMS-S-HP-100 system made by RUBOTHERM. This system can use maximum temperature-150°C and maximum pressure-40 MPa. Figure 1 shows a schematic diagram of the MSB experimental apparatus. Figure 2 shows a 3 position type MSB measurement system diagram. The high-pressure vessel was made of titanium and designed to withstand safely 20 MPa of pressure. The standard sinker, made of titanium, is freely suspended in sample solutions without contact with the pressure vessel, and the buoyancy change of the sample solutions measured. This pressure vessel can simulate the deep sea and/or the deep underground water conditions, where the temperature is over 100°C and pressure over 20MPa.. Therefore, the density change can be measured under all types of conditions, such as high temperature and pressure. The temperature of the CO2 solution inside the vessel can be adjusted from 273 K to 350 K by a water/oil bath system that can limit the temperature fluctuations within. 0.1 K. To enhance COz dissolution into water and maintain the homogenous temperature inside the vessel, a circulation pump was installed within the vessel. Before the experiment, water is fed into the high-pressure vessel under vacuum, up to the initial pressure, then all valves and pipe connectors are checked to exhaust the remainder of air in the measurement volume. This preparation of the high-pressure vessel was maintained for 24 hours for preliminary leakage tests by monitoring the pressure of water inside the vessel. As the first step of the experiment, an individual liquid CO2 droplet was injected into the water. Once this injected liquid CO2 droplet was completely dissolved (the pressure decreased from that at the completion of the droplet injection because of dissolution) another droplet was injected. These injection and dissolution processes were continued until the solution approached a saturated state, when the dissolution rate became much lower. The state when each droplet had dissolved completely was defined by temperature and pressure. Owing to the liquid CO2 dissolution rate reducing as the experiment progressed, this entire experiment took a few days to complete. .-,...

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1677

Mach-Zender interferometry (M-Z)system The fundamental principle applied in this study is laser interference. Physically, the refractive index of the solution will change once carbon dioxide has been dissolved in it. This refractive index difference can be detected and used as primitive data to calculate the density change by an equation derived from the original Lorentz-Lorenz formulation. More details were described in our previous paper. [7,8,10] E X P E R I M E N T A L R E S U L T S AND D I S C U S S I O N This study obtained a set of data of CO 2 water solution density at temperature of 293 K, pressure from 5 to 15.0 MPa, and CO 2 concentration up to 0.045 (in mass fraction). It was found from these data that the density of CO s dissolved water is non-linearly proportional to the CO s mass fraction in general. This relationship seems to be approximately a linear one. However, the ratio of density of CO s dissolved water to that of water with an associated state (water density at same pressure and temperature) and the difference between those densities appears to be a monotonically linear relationship with the CO s mass fraction and seems to be independent of pressure and temperature under the present experimental conditions noted above. The slope of this linear function is 0.32, being calculated by experimental data fitting. Figure 3 gives the data measured and curve fitted. Some deviations may have resulted from measurement error and pressure deviation from the indicated value. Regarding the theoretical estimation, this experiment showed that Haugen & Drange [4] gave a reasonable but a slightly lower slope, based on the data they chose, that are 19,=1.03x10 3 k g / m 3 and partial mole volume of CO s in seawater of 34x10 6 m3/mol. On the other hand, the solution density is directly proportional to the pressure at any given CO s concentration. Following the method of Ohsumi [5], the measured data of CO s seawater solution density p was normalized by seawater density at same thermodynamic state Po. This seawater density 9e was calculated, as a reference value, by pressure and temperature recorded at each experiment point of CO s water solution density measurement. The normalized density (the density difference defined by Ap=p-Pe)is plotted in Figure 3 as a function of CO s concentration. This density difference appeared to be linearly mono-correlative with CO s concentration for all of the experiment data in this study's conditions. With this result, it seems to be reasonable to suggest that the density difference Ap be a linear-monotonic increasing function of CO 2 concentration only and in depending on pressure and temperature. 0.02

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Figure 3: Comparison of density difference of CO2 water solution m e a s u r e d b y MSB and M-Z methods

1678 The mechanism of increasing CO2 solution density with CO2 gradually dissolving into water might, in principle, be expressed by the interaction between water and CO2 molecules. In fact, the size of the CO2 molecular is smaller than the distance between two water molecules, which allowed the former to be inserted into the gaps between water molecules, once dissolved. Furthermore, the molecular number density of CO2 solution becomes higher than that of pure water and leads the CO2 solution density to finally increase. On the other hand, it could, in general, be estimated that the density of the CO2 solution should be the function of pressure, temperature (like that of pure water or pure CO2) and the mass fraction of CO2 dissolved as well. That is true if the data were not normalized by the density of pure water. As had been mentioned above, this conclusion indicates extensively that the ratio of density of CO2 dissolved water to that of pure water will be kept constant at the same CO2 mass fraction and independent on the depth (ie. pressure and temperature) when CO2 ocean sequestration and CO2 aquifer sequestration are applied in practice. This also confirmed the suggestion that CO2 dissolved water will break down the original ocean/aquifer stratification state and produce a negative-buoyancy. The slope of this linear function is 0.273 g/cm3/wt, calculated by fitting the experimental data. For comparison with the properties of the CO2 water solution, two sets of experiment data of density difference for the MSB method and M-Z method are shown in Figure 3. It was found that the slopes of these two linear functions of CO2 concentration were slightly difference. This will not be discussed further here, as it is obviously out of the range of this paper and will be reported individually. CONCLUSIONS CO2 water solution density was experimentally investigated in this study at conditions of temperature of 293 K, pressure from 4.0 - 12.0MPa, and concentration up to 0.045 using the MSB method. The following conclusions were obtained: 1). Carbon dioxide water solution density increased with the increasing of the mass fraction of carbon dioxide in its water solution. 2). The density difference between the carbon dioxide water solution and pure water is monotonically linearly proportional to the CO2 mass fraction and independent of pressure; 3). The slope of this linear function of density difference between CO2-water solution and pure water, with respect to CO2 mass fraction, is 0.32 g/cm3/wt, which is slightly greater than that of the M-Z method result of 0.275 g/cm3/wt. ACKNOWLEDGEMENTS This study is a part of the investigation of the CO2 Ocean Sequestration Project and CO2 Geological Storage Project managed by Research Institute of Innovative Technology for the Earth (RITE) and funded by New Energy and Industrial Technology Development Organization (NEDO), Japan. REFERENCES 1. Marchetti,C. (1977) ClimaticChange; Vol.1, pp.59-68. 2. Haugan, P.M., Thorrildsen, E and Alendal, G (1995)Energy Conversion and Management; 36, pp.461-466. 3. Liro, C.R., Adams E.E., Herzog H.J. (1992) Energy Conversion and Management, 33 pp.667-674. 4. Haugan, P.M. and Drange, H. (1992)Nature; 357, pp.318-320. 5. Ohsumi, T., Nakashiki, N., Shitashima, K. and Hirama, K. (1992) Energy Conversion and Management, 33, pp.685-690. 6. Aya I. (2000) Proc. of Japanese Chemical Engineering Symposium, Miyazaki, Japan, 17 (in Japanese) 7. Song, Y.C., Nishio, M., Chen, B.X. and Akai, M. (2001) Sixth International Carbon Dioxide Conference, Sendai, Japan pp.760-763. 8. Song, Y.C., Nishio, M., Chen, B.X. and Akai, M. (2002) Proceedings of 5th International Symposium on C02 Fixation and Efficient Utilization of Energy, Tokyo, Japan pp.54-58. 9. Wagner, W., Brachthauser K., Kleinrahm, R. and Losch, H.W. (1995) International Journal of Thermophysics, 16, p.399-411. 10. Uchida, T., Ebinuma, T., Narita, H. and Someya, S. (1999) 2"d International Symposium on Ocean Sequestration of Carbon Dioxide, Tokyo, Japan pp.28-63 11. Yamane,K., Aya, I., Nariai, H. (1997) Proceedings of the Second Ocean Mining Symposium, Seoul, Korea.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved.

1679

ESTIMATIONS OF INTERFACIAL TENSIONS BETWEEN LIQUID CO2 AND WATER FROM THE SESSILE-DROP OBSERVATIONS T. Uchida, R. Ohmura, S. Takeya, J. Nagao, H. Minagawa, T. Ebinuma and H. Narita Institute for Energy Utilization, AIST Sapporo 062-8517, Japan

ABSTRACT

The interfacial tension between liquid CO2 and water or NaC1 solution was measured by a simple sessiledrop method at pressures up to 25 MPa and at temperatures of 278 and 288 K. The interfacial tension between liquid CO2 and pure water was approximately 38 mN m -1 at 288 K and 5 MPa with a small pressure dependence, whereas the values between liquid CO2 and 3 wt% NaC1 solution were more than 10 % larger than those between liquid CO2 and pure water. At 278 K, CO2 hydrate is stable and the interfacial tension has larger pressure dependence. This might be related to the supersaturation prior to hydrate formation. INTRODUCTION

Greenhouse gases, such as COz, have become a serious problem for mankind. To offset the CO2 emissions into the atmosphere, sequestration of CO2 in the deep ocean has been proposed. The behavior of CO2 injected into seawater can be predicted from the CO2-H20 phase diagram and a depth profile of the seawater temperature. In addition, the interfacial tension between liquid CO2 and water (or sea water) is an important factor for understanding the behavior of the injected CO2 droplets into deep water. However, CO2 hydrate formation on the droplets at depths deeper than 400 m [ 1] makes the prediction of CO2 dissolution difficult due to insufficient knowledge of the relevant physical parameters. CO2 hydrate is an ice-like clathrate compound formed from CO2 and water under suitable conditions of low temperature T and high pressure P. This crystalline compound will form at the interface between the injected liquid CO2 and seawater and can reduce the dissolution rate of CO2 into seawater. Furthermore, when liquid CO2 is injected into seawater under hydrate-forming conditions, the interfacial tension between these liquids can be difficult to estimate. In general, it is very difficult to measure the interfacial tension at high pressure and low temperature conditions. Uchida et al. [2] measured the interfacial tension between liquid CO2 and water by microscopic observations of pendant water droplets in liquid CO2 at T = 266.3-284.9 K and P = 2.7-6.0 MPa. They determined the temperature-dependent interfacial tension between liquid CO2 and water. Also, Uchida et al. [3] determined the interfacial tension between water and both CO2 vapor and COz liquid at T = 274.7-290.6 K and P < 5 MPa from observations of sessile drops. They found that the interfacial tension of water and liquid CO2 was about a half of that between water and CO2 vapor. For the present study, we used a simple method to estimate the interfacial tension between liquid CO2 and water by improving the method used by Uchida et al. [3] so it could be used at higher pressures. This method allowed us to measure not only the interfacial tensions at arbitrary P-T conditions and for various solutions, but also the variation of the interfacial tensions when the P-T conditions were changed.

1680 EXPERIMENTAL PROCEDURES A high-pressure vessel equipped with two optical windows was used for the observations. The inner volume of the vessel was approximately 10 cm 3. The vessel was filled with commercially available CO2 (purity of about 0.99) through a double-plunger, high-pressure pump, which controlled the pressures between 5 and 30 MPa. Distilled, de-ionized water or 3 wt% NaCI solution was then injected into the vessel through the stainless steel tube using another pump (FLOM Type 301). A sessile drop of the solution formed at the flared, cone-shaped end of a stainless steel tube equipped on the vessel bottom. The size of the sessile drop was several millimeters in diameter. Temperature was controlled to within + 0.2 K by a cooling jacket connecting the cooling bath, and was measured with a T-type thermocouple. The pressure was measured by a pressure-transducer (Kyowa type PH-300KB); its accuracy was --0.15 MPa. The experimental temperature was set at 278 K and 288 K with pressures ranging from 5 to 25 MPa. The shape of the water droplet was observed through a backlight, microscope-CCD camera system and recorded by an S-VHS video system. Figure 1 shows a schematic of the sessile drop and its shape parameters. Liqu

Figure 1: A sessile drop with the coordinates system.

Figure 2: Typical image of the sessile drop of pure water (T = 278 K, P - 5 MPa).

The interfacial tension ~LWbetween liquid CO2 and water (or ~?LSfor 3 wt% NaCI solution) was estimated from the shape parameters of the sessile drop with the following equation [4]: ~'LW= Ap g (H~ / G(Ht~/D~))2 where Ap is the density difference between liquid CO2 and water, g is the gravitational acceleration, H~ and D~ are the shape parameters shown in Figure 1 and G is the shape function. To make the estimation process easier, we measured the shape parameters only for ~ = 90 ° and used a computer system. The density differences between liquid CO2 and water were estimated from data obtained by interferometric measurements [5] and solubility data of CO2 in water [6]. The density differences between liquid CO2 and 3 wt% NaC1 solution were estimated from experimental and theoretical data [7]. In both estimates, we assumed that the density of liquid CO2 was same as that of pure liquid CO2 because the solubility of water in liquid CO2 is small. The densities of both pure liquid phases were calculated from the experimental data by using the commercially supplied PROPATH program [8]. The resulting accuracy of 3, is strongly affected by the accuracy of Ap, especially at higher pressures due to the small value of Ap. Since we cannot measure Ap directly in the present study, the estimated error is larger at higher pressures. RESULTS AND DISCUSSIONS Figure 2 shows a typical image of a sessile drop. Our stepwise increases of pressure every 20 minutes gave

1681 the interfacial tensions at various pressures and the slight change in the interfacial tensions with time due to the change of conditions. Figure 3 shows (a) YLW and (b) ?LS at 278 K (circles) and 288 K (triangles) with pressure. Open and solid marks indicate the data measured just after a pressure increase and just before the next pressure increase, respectively. The minimum error of y is estimated at approximately __+3.5% at T = 288 K and P = 5 MPa as shown by the error bar, whereas the maximum is - 2 0 % at T = 278 K and P = 20 MPa. Figure 3(a) shows that YLWranges between 20 and 32 mN m -1 at 278 K and between 30 and 38 mN m t at T = 288 K, both of which depend on pressure: higher pressures have lower interfacial tension values. The pressure dependence is larger at 278 K than at 288 K. It also shows that 7LW dropped immediately after the pressure change and gradually increases with time. 50

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Figure 3: Pressure and time dependence of interfacial tensions between liquid CO2 and (a) pure water (b) 3 wt% NaCI solutions. The solid square indicates the value obtained by Uchida and Kawabata [2]. Other open marks indicate the values immediately after the pressure increase, and solid marks are measured 20 minutes after the pressure change. The observed values of ]tLW in the present study agreed with those obtained previously [2, 3]" the average value of 7LW was estimated to be approximately 30 mN m ~ at T = 278 K and P = 4 MPa. This agreement indicates that the interfacial tension from both methods agree quantitatively within experimental accuracy. Figure 3(b) shows that ?LS ranged between 30 and 37 mN m -I at 278 K and between 39 and 50 mN m ~ at 288 K. These values are approximately 10% larger than those observed in pure water system at P = 5 MPa. This change likely results from the effect of ions Na + and CI in water, which can change the structure of the solution. The figure also indicates that both interfacial tensions generally depend on pressure; in particular, that observed for NaCI solution at 278 K is weaker than for pure water, whereas the interfacial tension for NaC1 solution at 288 K increases with pressure. It is known that the decrease in liquid-fluid interfacial tension accompanies with increase in mutual solubility [9]. The pressure dependences of the CO2-water interfacial tensions indicated in Figure 3 coincide with such general feature of the interfacial tensions in systems of two-fluid phases, as the mutual solubility in the liquid-CO2-water system increases with an increase in pressure. The pressure dependence of interfacial tension at 278 K is larger than that at 288 K, which might be due to the difference in the stable conditions at the two temperatures. 288 K is higher than the equilibrium temperature of CO2 hydrate at each pressure of the present interest. Thus, at 288 K the liquid phases can be in stable equilibrium condition. However, at 278 K the stable condition for the two liquid phases are

1682 metastable or supersaturation with respect to CO2 hydrate formation. Under metastable conditions, the mutual solubility is higher than that in stable equilibrium with hydrate, and the pressure dependence in the mutual solubility might be larger than that at higher temperatures where two liquid phases can be in stable equilibrium conditions. This argument may be supported by the aqueous phase viscosity measurements before and after the CO2 hydrate formation [10]. The viscosity of CO2 aqueous solution increases before hydrate nucleation and drops just after the nucleation. This implies that the mutual solubility increases prior to the hydrate nucleation, which is under metastable conditions. The difference between open and solid marks at each pressure apparently indicates time dependence of the interfacial tension. It should be noted, however, that the apparent time-dependence is not dynamic variation in interfacial tension in the system, but rather artifact in the experimental scheme employed in the present study. The density of liquid water saturated with CO2 is used in the present calculation to determine the interfacial tension. But the saturation or dissolution of CO2 into liquid water, i.e., diffusional or convective mass transfer of CO2 into liquid water, does not cease quickly but proceeds for a certain long time. Therefore, A9 gradually changes and the resulting g also gradually increases. In conclusion, the interfacial tensions between liquid CO2 and water and between liquid CO2 and NaC1 solution were measured by a simple sessile-drop method at pressures up to 25 MPa and temperatures of 278 and 288 K. The interfacial tension between liquid CO2 and pure water is approximately 30 mN m 1 at T = 278 K and P = 5 MPa with a large pressure dependence. Within experimental accuracy, these values agree with previous measurements. The interfacial tension between liquid CO2 and 3 wt% NaC1 solution is more than 10% larger than that in pure water. However, when the temperature is above that for CO2 hydrate dissociation, the interfacial tension has little pressure dependence compared with that at T = 278 K. The large pressure dependence at 278 K might be related to the supersaturation prior to hydrate formation. ACKNOWLEDGEMENTS This study was done with the collaboration of Professor Y. H. Mori in the Department of Mechanical Engineering, Keio University. This work was partially managed by the Research Institute of Innovative Technology for the Earth (RITE) and supported by the New Energy and Industrial Technology Development Organization (NEDO) through the Research and Development on CO2 Ocean Sequestration Project. Another part of this work was supported financially by the NEDO-grant (00B60016d). We also thank Professor E. D. Sloan, Jr., Professor K. Ohgaki, Dr. T. Ohsumi, Dr. S. M. Masutani, Dr. M. Ozaki and Dr. H. Ohyama for their fruitful discussions, and to Ms. M. Akaike for her help on the data analysis.

REFERENCES 1. Lund, P. C., Shindoh, Y., Nakashiki, N. and Ohsumi, T. (1995). Energy Convers. Mgmt., 36 827. 2. Uchida, T. and Kawabata, J. (1997). Energy, 22, 357. 3. Uchida, T., Ebinuma, T.. and Narita, H. (2000). Proc. Int. Syrup. Deep Sea Sequestration of C02, Tokyo, Feb. 1-2, 2000, 1-4-1-6. 4. Prokop, R.M., del Rio, O.I., Niyakan, N. and Neumann, A.W. (1996). Can. J. Chem. Eng., 74, 534 5. Song, Y.C., Nishio, M., Chen, B.X., Someya, S., Uchida, T., Akai, M. and Masuda, S. (2001) Proc. 6 th Int. C02 Conf., Sendal, Oct. 1-5, 2001, 760. 6. Dodds, W. S., Stutzman, L. F. and Sollami, B. J. (1956). Ind. Eng. Chem., Chem. Eng. Data Ser, 1, 92. 7. Teng, H. and Yamasaki, A. (1998). J. Chem. Eng. Data, 43, 2. 8. PROPATH-a Program Package for Thermophysical Properties of Fluids, Ver. 7.1. Corona Publishing, Tokyo, Japan, 1990. 9. Donahue, D.J. and Bartell, F.E.. (1952). J. Phys. Chem., 56, 480. 10. Ohyama, H., Ebinuma, T., Shimada, W., Takeya, S., Nagao, J., Uchida, T. and Narita, H. (2002). Proc. 4 th Int. Conf. Gas Hydrates, Yokohama, May 19-23, 2002, 561.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1683

LETHAL EFFECT OF ELEVATED pCO2 ON PLANKTONS COLLECTED FROM DEEP SEA IN NORTH PACIFIC

Y. Watanabe 1'2, A. Yamaguchi 3, H. Ishida l, T. Ikeda 3, j. Ishizaka 4 1 Kansai Environ. Engineer. Center Co., ltd., Azuchi-machi, Chuo-ku, Osaka, 541-0052, Japan 2 Graduate School of Marine Science and Engineering, Nagasaki University, Bunkyo-machi, Nagasaki 8528521, Japan 3 Graduate School of Fisheries Sciences, Hokkaido University, Minato-cho, Hakodate 041-0821, Japan 4 Faculty of Fisheries, Nagasaki University, Bunkyo-machi, Nagasaki 852-8521, Japan

ABSTRACT

We observed the lethal effects of high partial pressure of CO2 (pCO2) to the pelagic zooplankton. The experiments were performed from the sub-arctic to the sub-tropical region and compared the sensitivities to the high pCO2 between surface organisms (0 - 500 m) and deep-sea organisms (500 - 1,500 m). When organisms were exposed at a pCO2 from 500 to 100,000 ~tatm, half the organisms died within 1 day to 2 weeks after exposure. From the half lethal time (LT50) calculated from the survival curve, higher pCO2 resulted in earlier death of the zooplankton. However, deep-sea animals in the sub-arctic region were less sensitive to the increasing of pCO2 compared with the others. The apparent LT50 on higher pCO2 showed that deep-sea organisms are more tolerant than surface ones.

INTRODUCTION

Ocean sequestration of CO2 has great potential for the mitigation of the increasing levels of atmospheric CO2, but there is little information about the environmental effects, especially to deep-sea organisms. These appear to be more sensitive to the environmental change than surface organisms[ 1,2], as the environmental fluctuation in the deep sea is less than that of the surface layer. If deep-sea organisms have high sensitivity to high CO2, it is necessary to compensate in order to apply the experimental results for deep-sea organisms. However, there is no information to evaluate the above problem. To assess whether deep-sea organisms have higher sensitivity to high pCO2 than surface ones, we conducted exposure experiments using zooplankton collected from the surface and deep layer in the Pacific.

EXPOSURE EXPERIMENT

Experiments were conducted from the subarctic (44N) to the subtropical region (11N) in the westem North Pacific. Zooplankton were collected from 500 m to surface, and from 1,500 m to 500 m by the vertical towing of a modified NORPAC net and VMPS-6000 (Vertical Multiple Plankton Sampler, Fig. 1), respectively. Healthy animals were selected and kept in several concentrations of pCO2 controlled with mixed gases (N2, 02 and CO2). The survival rate in each bottle was observed during the experiment.

1684

Figure 1: Vertical Multiple Plankton Sampler (VMPS-6000) for collection of deep-sea zooplankton

In the subarctic region, Euchaeta marina, Metridia pacifica and Calanus pacificus in surface and Neocalanus cristatus, Paraeuchaeta birostrata, Gaidius variabilis, and Heterostylites major in deep-sea group were exposed. In addition, in the subtropical region, we could not separate each species because of their small size and large diversity; we then took animals with the epipelagic (surface) group and mesopelagic (deep) group. Compared with zooplanktons exposed in intact pCO2 (for example, 8001aatm in E. marina, 8601aatm in N. cristatus), zooplankton with higher pCO2 died sooner. There was a difference on the mortality time between animal species; for example, E. marina died earlier than N. cristatus (Fig. 2). Because a high concentration of C O 2 in sea-water causes a low pH, the effects of CO2 were estimated from the results of the experiment exposed in low pH[3]. To evaluate the data, we calculated the half lethal time (LT50) and compared this with the LC50 resulting from the HCI exposure experiment[4] on pelagic zooplankton. The LT50s in high pCO2 exposure were shorter than those in the low pH exposure experiment, at converted pH. This shows that the estimate of the effect of high pCO2 from the results of the low pH experiment tended to underestimate the impact. It is important to experiment actually using CO2 for the assessment of the sequestrated CO2 in the ocean. In our poster, the vertical comparisons between the surface and deep layer are discussed from the LT50 calculated from the actual experiment. Neocalanus cristatus

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--e-pco2=800/z arm (pH7.88) pCO2=llOO/zarm (pH7.74) -~- pCO2=5500.u at,In IpH7.11) --'--pC02=8800 U arm pH6.89) ~pC02=21000~ arm t,p|t6.58)

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Figure 2: Died copepods in various pCO2

12

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~'o

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Figure 3: Half lethal time of zooplanktons in high pCO2 (close circle) and in low pH (open circle)

AKNOWLEDGEMENT

This study is a part of WEST-COSMIC (Western north Pacific Environmental Study for CO2 sequestration for Mitigation of Climate change) conducted by NEDO (New Energy Development Organization) supported by the Ministry of International Trade and Industry. We thank the crew of Hakureimaru No.2 for their great help.

REFERENCES

Omori, M., Norman, C. P. & Ikeda, T. Oceanic disposal of CO2: potential effects on deep-sea plankton and micronekton- a review. Plankton Biol. Ecol. 45, 87-99 (1998). Shirayama, Y. Biodiversity and biological impact of ocean disposal of carbon dioxide. Waste Management 17,381-384 (1997). Auerbach, D. I., Caulfield, J. A., Adams, E. E. & Herzog, H. J. Impacts of ocean CO2 disposal on marine life: I. A toxicological assessment integrating constant-concentration laboratory assay data with variable-concentration field. Environ. Model. Assess. 2, 333-343 (1997). Yamada, Y. & Ikeda, T. Acute toxicity of lowered pH to some oceanic zooplankton. Plankton Biol. Ecol. 46, 62-67 (1999).

This Page Intentionally Left Blank

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1687

THERMODYNAMIC RELATIONSHIP TO ESTIMATE THE EFFECTS OF HIGH CO2 CONCENTRATION ON THE CO2 EQUILIBRIUM AND SOLUBILITY IN SEAWATER C.S. Wongl, p.y. Tishchenko 2 and W.K.Johnsonl lInstitute of Ocean Sciences, 9860 West Saanich Road, Sidney, BC V8L 4B2, Canada 2Pacific Oceanological Institute, 43 Baltiyskaya St., Vladivostok 690041, Russia

ABSTRACT

The effects of high CO2 concentrations on carbonate equilibrium are important in studies related to the disposal of liquid CO2 into the oceans. Using available thermodynamic data of liquid CO2 and CO2 solubility in seawater, an equation of solubility of liquid CO2 in seawater was developed as a function of temperature, pressure, and salinity. It is shown that the non-ideal behavior of acid-base species subjected to high CO2 conditions can be accounted for by Pitzer's parameters. The solubility of liquid CO2 in seawater between values from calculation using thermodynamic equations and those from literature was presented. The pH of seawater equilibrated with liquid CO2 was calculated to be elevated by approximately 0.20 pH unit due to the non-ideal effects of dissolved CO2 on acid-base equilibrium. Effects of high CO2 on seawater alkalinity are discussed. INTRODUCTION

The interaction of liquid CO2 with seawater results in high CO2 concentrations. Technical assessment of environmental condition for a pool of liquid CO2 has to include measurements of two parameters of the carbonate system as a minimum, in order to calculate the others. The commonly accepted procedure for the calculation of the carbonate system of seawater includes equilibrium constants which were determined at trace concentrations of dissolved free CO2 in seawater where [CO2] = [CO2]aq + [H2CO3]aq. (1) This paper uses a theoretical approach, which permits us to take into account the effects of high CO2 concentrations on acid-base equilibrium using the ionic interaction approach or Pitzer method [Pitzer, 1973, 1991].

Solubility of liquid C02 in the seawater Here, we develop a thermodynamic approach for estimation of the solubility of liquid CO2 in seawater as a function of temperature (T), pressure (P), and salinity (S). This approach includes using Henry's Law for solubility of liquid CO2 along boiling T°, pb line, because there is CO2-gas phase for such case and taking into account P V - work from pb to given P. Superscript "b" refers to boiling conditions of the liquid CO2. The equation for solubility of liquid CO2 is as follows:

1688

ln[C02°]=-34.22346 -0.0317715 • T + 5357.744 / T + 0.000004810 • T 2 + 23.3585-ln(T /100) + S. [0.021486 -0.022291 • T /100 + 0.0044787 • (T /100) 2] + (2) (-0.0277106 + 0.00005508 • T + 3.67376 / T). 10 -5 • P + (0.030013 -0.00005818 • T - 3.9489 /T). 1 0 - t 3 • p2 where P is in Pa. There is a relationship between two concentration scales, as follows:

[CO:,] = [C02°]/(1 + 0.04401 .[C02°]), where, [CO2] is moles of CO2 in lkg seawater which contains CO2. Comparison between our calculations and direct measurements of solubility of liquid CO2 is presented and discussed Using equation (2) we calculated a profile of CO2 concentration in seawater for a column equilibrated with liquid CO2 (Figure 1). From this figure we see that CO2 concentrations varied from 1.29 (400 m) to 1.67 mol-(kg-soln)l (4282 m). Such high CO2 concentrations should change the constants of the carbonate system. [CO2I, mol(kg-soln) "l 1.2 0

500

-

1000

=

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-

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1.5

1.6

1.7

w

w

w

w

•

2000

o

2500

-

3000

3500 4000

-

4500

-

Figure 1:CO2 concentration of column seawater equilibrated with liquid CO2. Calculations were carried out using eq.(2) and CTD data for "Papa" station, Cruise 9910. DISCUSSION Alkalinity can be measured accurately in a given region before C O 2 injection and alkalinity is not affected by the addition of CO2. Using measured alkalinity data at Station P (50 ° N, 145°W) in the Northeast Pacific and the predicted CO2 concentrations (Fig.l) we calculated pH profiles at Ocean Station "Papa" using thermodynamic equations. Fig.2 demonstrates pH profiles with (a) and without (b) taking into account effects of CO2 concentrations on equilibrium constants. Differences between the two profiles changed with increasing depth by 0.173 to 0.247 pH units. Brewer et al. [2000] made direct pH measurements of the interaction of liquid CO2 and seawater at 619 m depth and t = 4.25 °C in the NBS scale. Their pH value is about 4.25 (original value converted into total concentration scale). For similar conditions, our predicted pH value is about 3.46. Apparently, the main difference between measured and predicted value is explained by the fact that full equilibrium between liquid CO2 and seawater was not reached because experimental conditions are meta-stable for liquid C O 2 - seawater equilibrium [Brewer et al., 2000]. The behavior of the carbonate system at high CO2 concentration has the distinct feature, that concentrations of the HC03 species are higher than alkalinity as is seen in Figure 3.

1689 p H 3.1 0

in

m

|tu

3.2

•

3.3

•

3.4

•

3.5

•

500 1000 1500 2000 2500

=

3000 3500 4000 4500

b

a

5000

Fig.2. pH profiles of"Papa" station (Cruise 9910) calculated with (a) and without (b) taking into account effects of CO2 concentration on the equilibrium constants. TA, [HCO3] , umol(kg) "1

2300

2350

2400

2450

2500

2550

0 500

•

mA

m&

1000

mi

I m-2)

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A-31J

1500 2000 m,

2500 3000 3500

•

•

•

4000 4500 5000

Figure 3: TA measured (1) of the "Papa" station (Cruise 9910), and concentration of riCO3 profiles calculated with (2) and without (3) taking into account effects CO2 concentration on equilibrium constants.

CONCLUSIONS Using Henry's Law and PV-work, the thermodynamic equation (2) for the solubility of liquid CO2 in seawater was derived. This equation was parameterized as a function of temperature, pressure and salinity using available thermodynamic data. It is shown that CO2 concentration of seawater equilibrated with liquid CO2 exceeds more than 1.3 moles.(kg) 1. Very high CO2 concentration results in low pH of

1690 seawater (less, than 4 pH unit). Under these conditions CO2 partly converts S042- a n d / r ions to HSO4and HF. Therefore, concentrations of HC03- will exceed total alkalinity. The effects of high CO2 concentration on the constants of the carbonate system were taken into account using combined approaches - Pitzer method and method of concentration constants. Non-ideal properties of dissolved CO2 in seawater shift the carbonate equilibrium with increase in pH. This shift is more than 0.20 pH unit when seawater is equilibrated with liquid CO2. REFERENCES

Brewer. P.G., Peltzer, E.T., Friederich, G., Aya, I., and Yamane, K.(2000) Mar.Chem., 72: 83. Pitzer, K.S., (1973) J.Phys.Chem, 77: .268. Pitzer, K.S., (1991). pp. 75-153, In: Activity Coefficients in Electrolyte Solutions. K.S.Pitzer (Ed), 2nd Edition,: CRC Press, Roca Raton. Teng, H. and Yamasaki, A., (1998). J. Chem.Eng.Data, 43:.2.

Greenhouse Gas Control Technologies, Volume II J. Gale and Y. Kaya (Eds.) © 2003 Elsevier Science Ltd. All rights reserved

1691

THE GOSAC PROJECT TO PREDICT THE EFFICIENCY OF OCEAN CO2 SEQUESTRATION USING 3-D OCEAN MODELS

James C. Orr 1, Olivier Aumont l, Andrew Yool 2, Gian-Kasper Plattner 3, Fortunat Joos 3, Ernst MaierReimer4, Marie-France Weirig 5, Reiner Schlitzer5, Ken Caldeira 6, Michael Wickett, Richard Matear 7, Bryan Mignone 8, Jorge Sarmient08, and John Davison 9 ILSCE/CEA Saclay, CEA-CNRS and IPSL, Gif-sur-Yvette, France 2Southampton Oceanography Centre (SOC), Southampton, UK 3Climate and Environmental Physics, Physics Institute, University of Bern (PIUB), Switzerland 4Max Planck Institut fuer Meteorologie (MPIM), Hamburg, Germany 5Alfred Wegener Institute for Polar and Marine Research (AWl), Bremerhaven, Germany ULawrence Livermore National Laboratory (LLNL), California, USA 7CSIRO, Hobart, Australia 8AOS Program, Princeton University, Princeton NJ, USA 9IEA Greenhouse Gas R&D Programme, Stoke Orchard, Cheltenham, GL52 7RZ, UK

ABSTRACT To evaluate the efficiency of the ocean in retaining purposefully sequestered CO2, eight ocean modeling groups made a set of standard injection simulations. Injection was made simultaneously at seven separate sites; separate 7-site simulations were made for injection at 800 m, 1500 m, and 3000 m. For injection at 3000 m, all models showed 85% or greater global efficiency in year 2200, i.e., 100 years after the end of the specified 100-year injection period; at the same time, the 1500-m injection is 60-80% efficient and 800-m injection is only 42-61% efficient. Most of the CO2 injected at 3000 m was lost from the Southern Ocean (the principal region by which the deep ocean is ventilated); at shallower depths, relatively more was lost sooner, from the northern hemisphere and the tropics. The simulated global injection efficiency at 3000 m is correlated with both the simulated global mean CFC-11 inventory and deep-ocean natural inc. Based on these correlations, the global observational constraints for these two tracers, and model diversity, it appears likely that the range of model-predicted efficiencies would bracket real ocean behavior under the same 3000m injection scenario.

INTRODUCTION A quarter of a century ago, it was proposed that one could help limit increases in atmospheric CO2 by diverting CO2 emissions from near-coastal power plants into the deep sea [ 1]. However, uncertainty remains concerning the science of such a strategy. A fundamental question is, how efficient would the ocean be in retaining purposefully sequestered CO2? Ocean models offer the only quantitative means to answer this question due to the century time scales involved for deep-ocean circulation. Simple ocean box models have been used to provide estimates of the ocean's mean retention efficiency [2]. Simulations with 3-D models can distinguish site-specific efficiencies. However until recently, only one 3-D model had been used for such studies and thus uncertainties had not been addressed. That changed with the initiation of the GOSAC

1692 project (Global Ocean Storage of Anthropogenic Carbon). Here we describe results from that project where standard simulations in seven different 3-dimensional global ocean models and one 2.5-dimensional zonal basin average model were systematically compared to provide measures of uncertainty about the ocean's efficiency at retaining purposefully injected CO2. Previously, we quantified global and site efficiencies for deep injection [3]. For example, the 3000-m injection is 85% or more efficient in all models in year 2200. At the same year, 1500-m injection is 60-80% efficient and 800-m injection is 42-61% efficient. We further showed that injection at 1500 m was most efficient at sites in the Pacific Ocean (San Francisco, Tokyo) and least efficient at sites in the Atlantic Ocean (New York, Bay of Biscay, and Rio de Janeiro). Here we outline why the most and least efficient sites differ, provide details about the 300-m injection, and assess if simulated global efficiencies are realistic.

MODELS AND SIMULATIONS The eight global ocean models used in this project have been described previously [3,4]. All models were first integrated to reach a steady state, equivalent to a pre-industrial state with atmospheric pCO2 at 278 ppm. Then the models were forced to follow observed atmospheric CO2 during years 1765-2000. Subsequently during 2000-2500, models followed IPCC future scenario $650, which eventually stabilizes atmospheric pCO2 at 650 ppm. Injection occurred only during years 2000-2100, with 0.1 Pg C year-1 (1 Pg C = 1015 g) injected offshore at each of seven sites (Bay of Biscay, Bombay, Jakarta, New York, Rio de Janeiro, San Francisco, and Tokyo). For each injection simulation, we used a separate tracer to track the each site's injected DIC plume. Nonlinearities due to this multi-tracer approach are negligible [5]. These standard injection simulations are further detailed elsewhere [3], with protocols at http ://www.ipsl.j ussieu, fr/OCMIP.

RESULTS For 1500-m injection San Francisco was generally the most efficient site and New York was the least efficient. Much of CO2 injected at 1500 m at New York was transported northward by the lower part of the Gulf Stream to the North Atlantic in the Norwegian and Greenland Seas. There it was brought back to the surface by deep winter mixing, where it could exchange with the atmosphere. In the North Pacific, some of the injected CO2 escaped back to atmosphere in the North Polar sub-polar gyre. Yet, winter convection in the North Pacific is shallower and less intense than in the Atlantic, thereby explaining its improved efficiency. The efficiency of the Rio de Janeiro site varies most among between models. As most of the CO2 injected at this location is lost in the Southern Ocean, this large predicted range reflects the large discrepancies between models in this region. Injection at 3000 m resulted in smaller differences between site efficiencies for a given model. The southern hemisphere sites (Rio de Janeiro and Jakarta) were generally the least efficient. The New York site efficiency improved dramatically, relative to the 1500-m injection, because the plume took a longer pathway to the surface by moving southward to the Southern Ocean. In the 3000-m injection simulation, all sites lost most of their injected CO2 south of 30°S (Fig. 1) even though five of the seven injection sites are located in the Northern Hemisphere; conversely, around half of CO2 from both shallower injections was lost from the northern hemisphere. With time, ocean mixing homogenized the distribution of injected CO2 in the deepocean, thereby enhancing loss from the Southern Ocean, which dominates deep-water ventilation in all the models. Although the southern region occupies about 31% of the surface area of the global ocean, loss is enhanced there owing to generally more efficient surface-deep water exchange.

1693 t~t~tud, ao's .toos ~o's ao-,~ ........ .t............... , ............... ~.............. ~............... ~............... L.............. ~............... ~............... J.......... 1.z 'i

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Figure 1: Zonal integral, cumulative loss of injected CO2 from ocean to the atmosphere (Pg C degree -l) DISCUSSION Comparison of simulated vs. observed ocean tracers provides a benchmark of model performance that helps to weigh model predictions. Radiocarbon has been measured extensively and its radioactive decay helps us assess the rate at which deep waters are ventilated. This ventilation rate may be related to injection efficiency. The group of models used in this study includes those that have deep waters that are too old to those that have deep waters that are too young. Therefore it would seem likely for the range of results to bracket the real behavior of the global ocean, if purposeful CO2 injection were actually carried out under the same scenario at 3000 m. Furthermore, natural C-14 and injection efficiency are correlated. For the 3000-m injection, the correlation has an R 2 of 0.57 (Fig. 2). The correlation is lower for the 1500-m injection and there is no correlation for the 800-m injection. Additionally, there is strong correlation (R 2 = 0.81) between the global inventory of another tracer, CFC- 11, and the global efficiency of the 3000-m injection (Fig. 2a). Conversely, there is no correlation with the global CFC-11 inventory for 800-m injection and only a slight correlation (R 2 = 0:31) for the 1500-m injection. Although, we expected to find some correlation with natural lac, a tracer of deep-ocean circulation, CFC-11 is a man-made transient tracer that only started being released to the atmosphere in the 1930's. The correlation of the 3000-m injection efficiency with the global uptake of CFC-11 (R 2 = 0.81) is even stronger than it is for natural ~4C (R 2 = 0.57). One reason may be that surface-to-deep ocean exchange limits CFC uptake as well as loss of injected CO2 to the atmosphere. Further, most of this CFC-11 uptake and most of the loss of CO2 injected at 3000 m occur in the Southern Ocean. Another reason is that both CFC-11 and injected CO2 are transient tracers, and natural 14C is not a transient tracer. The transient tracer argument by itself does not explain the increase in correlation with injection depth, but it does seem to help explain the better correlation of the 3000-m injection efficiency with CFC- 11 than with natural ~4C. The observational constraint for the global mean 14C below 1000 m is about -150 permil [6], and the model results bracket -150 permil. There is not yet an observational constraint for the global inventory for CFC-11" however, the OCMIP-2 CFC-11 model-data comparison along available sections suggests that the models

1694 also bracket the CFC-11 observations. Therefore based on these observational constraints and correlations from two tracers, the range of GOSAC/OCMIP-2 simulated efficiencies for the 3000-m injection would be likely to bracket real ocean behavior given the same injection scenario. 100

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Shrubs (D1.33. Development of the catalyst to suppress the coke formation is essential to decrease the amount of steam required and achieve the optimum H2/CO ratio. Also, it is contributing towards enhancing the efficiency of the process by reducing the amount of input gas. For the depression of carbon formation on the catalyst, addition of alkali to the support [2] or highly dispersed Ni [3] has been reported as being effective. In particular, an alkali support has been reported to enhance the adsorption of carbon dioxide, resulting in conversion of carbon to CO. Based on these studies, we have been researching durable catalysts for methane reforming using CO2 with two applications: a) Ni-substituted hexaaluminate catalyst b)Addition of Ca RESULTS

Ni-substituted hexaaluminate catalyst Hexaaluminates are the compounds which have a /3-alumina, or magnetplumbite, or related layered structure [4]. It is possible to substitute part of the AI by a transition metal such as Mn or Ni. Since this structure can retain a high surface area (>10m2/g) at high temperature, Mn-substituted hexaaluminate has been reported to be useful for high-temperature catalytic combustion [5]. However, there are only a few concerning the application of hexaaluminates for methane reforming [6,7]. We prepared Ni-substituted

1848 barium hexaaluminate (BaNiAlllOl9) and examined the effect of reduction condition, reforming activity, and coke formation in the methane reforming with H20 and CO2.

Catalyst Preparation Ni-substituted hexaaluminate catalyst was prepared via two processes. The powder mixture process is a simple method and suitable for obtaining good strength. The Alkoxide process is the method used to obtain large surface area

Powder mixture process (PM) The powder mixture of A1203, BaCO3, NiO is ground and compressed into a pellet form, then calcined at 1500°C for 1Oh; this is ground into particles with a diameter of 300-850 # m.

Alkoxide process (ALK) Ba metal and Al(OC3H7)3 were stirred in 2-propanol until dissolution was complete. The solution was refluxed at 80°C for 3h under N2. An aqueous solution of Ni(NO3)2 was introducing dropwise into the alcoholic solution. The resulting gel was dried at 110°C, then calcined at 1300°C for 5h. For comparison, 5wt%Ni/o~ A1203 was prepared. An aqueous solution of Ni(NO3)2 was dropped into o~A1203 with a particle size of 300-850 ~z m, dried at 110°C, then calcined at 700°C for 6h.

Reduction of Catalyst When the Ni-substituted hexaaluminate(BaNiAlllO19) was reduced at 700°C, no reforming activity was observed. TGA measured in 50% Hz/N2 flow showed that BaNiAlllOl9 was reduced over 850°C while Ni/AI203 was reduced around 400°C.(Figure 1)

.............................................. BaNiAhxOt9(PM)

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400 600 Temperature(°C)

800

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TGA results in 50%H2/N2 flow

SEM photograph of BaNiAlllOl9(PM) before and after reduction at 900°C for lh were shown in Figure 2.

Figure 2:

SEM of the BaNiAlllOl9 before (A) and after(B) reduction

After reduction, a number of particles were formed on the surface of the catalyst, which were confirmed by EDX measurement to be Ni metal. The size of particles seems to be uniformly 20-30/~ m, which is not so small as a supported catalyst.

1849 The surface area of the catalysts were measured by N2 adsorption at 77K (Table 1). As expected, BaNiAllIO19 prepared by the alkoxide process has a large surface area. Also, H2 adsorption at 298K was measured after reduction. Depending on the difference of the surface area, BaNiAIIIOI9(ALK) showed a larger amount of adsorption than BaNiAlllOl9(PM). Ni/AI203 has more than the double the amount of Ni on the surface than that on the hexaaluminate catalyst. TABLE1 SURFACE AREA AND H2 ADSORPTION OF CATALYST Catalyst

Surface area(m2/g)

5%Ni/AIzO3 BaNiAll lO 19(PM) BaNiAll lO 19(ALK)

H2 adsorption(ml/g)

2.5 1.9 14.3

0.38 "l 0.12 *2 0.18 '2

•l After reduction at 700°C for 1h..2 After reduction at 900°(2 for 1h.

Activity Test Methane reforming reaction with H20 and CO2 was carried out at 700°C under atmospheric pressure, CH4/H20/CO2=3/2/1, SV=72,000ml/g-cat h, process time=15h. Before the reaction, catalysts were reduced for lh at 700°C(Ni/AI203) or 900°C(BaNiAlllOl9). The results are shown in Table2. TABLE 2 RESULTS OF THE ACTIVITY TEST Catalyst . 5%Ni/AI203

CH4 cony.(%)"~ 24.4 BaNiAI iiO 19(PM) 19.6 BaNiAllIOI9(ALK) 24.2 "Average conversion for 15h.

Coke(wt%) 11.7 0 0

Inlet pressure was increasing

All the catalysts maintained constant methane conversion, but in the case of Ni/A1203, the inlet pressure increased steadily because of coke formation in the catalyst bed. TGA analysis of the catalysts after reaction revealed l l.7wt% carbon for Ni/AI203, while no coke was found on the hexaaluminates. An SEM photograph of the catalyst surface confirmed the difference (Figure3). For Ni/AI203, coke covered the active site completely and formed a number of whiskers, while the surface of BaNiAlllO19 remained clear.

Figure3: SEM of the catalyst after reaction 5%Ni/A1203(A) and BaNiAIllOI9(PM)(B) Methane conversion of BaNiAII1OI9(ALK) was about 5% higher than BaNiAlllO19(PM), as expected by the difference of the surface area. Comparing the reforming activity per Ni based on the data in Table 2, hexaaluminates was much higher than Ni/A1203. Conversely, coke formation rates were opposite. Such a difference in catalytic property was thought to be due to the interaction between the Ni and the support or the uniformity of Ni size in BaNiAlllOl9.

Addition of Ca Alkaline metal and alkaline earth metals have been recommended for decreasing coke formation [8,9]. Here,

1850 the influence of the support was studied when various amounts of Ca was added. Experiments

Promoted Ni/SiO2 and Ni/c~ A1203 were prepared by direct impregnation of SiO2 powder and o~-A1203 particles (60-80 mesh) with the solution of Ni(NO3)2 and nitrate of promoter. The catalyst was tested in a quartz reactor with a CH4:CO2=1:1 feed gas without dilution at 800°C under atmospheric pressure, SV=60,000ml/g-cat h, process time=4h. Results and discussions

Alkaline metals (K, Cs) showed excellent coke resistance ability with a sacrificed loss of reforming activity. Small amount o f K (K/Ni