Offshore Magazine - January 2011

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For continuous news & analysis www.offshore-mag.com

January 2011

World Trends and Technology for Offshore Oil and Gas Operations

Gulf of Mexico update Drilling outlook Discovery survey Deepwater Horizon aftermath New bidding model

Seismic-while-drilling helps reduce uncertainty io ct

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E: odu D I pr ter S IN ting pos loa els /i F ess em v

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MqM q THE WORLD’S NEWSSTAND®

𰀳𰁊𰁊𰁗𰁌𰁓𰁖𰁉𰀄𰁈𰁖𰁍𰁐𰁐𰁍𰁒𰁋𰀄𰁖𰁉𰁕𰁙𰁍𰁖𰁉𰁗𰀄𰁅𰀄𰁗𰁘𰁖𰁅𰁘𰁉𰁋𰁝𰀐𰀄𰁉𰁗𰁔𰁉𰁇𰁍𰁅𰁐𰁐𰁝𰀄𰁍𰁒𰀄𰁘𰁓𰁈𰁅𰁝𰂫𰁗𰀄𰁉𰁒𰁚𰁍𰁖𰁓𰁒𰁑𰁉𰁒𰁘𰀄𰁛𰁌𰁉𰁖𰁉𰀄𰁘𰁌𰁉𰀄𰁛𰁖𰁓𰁒𰁋𰀄𰁑𰁓𰁚𰁉𰀄𰁇𰁅𰁒𰀄𰁆𰁉𰀄𰀄𰁑𰁓𰁖𰁉𰀄𰁇𰁓𰁗𰁘𰁐𰁝𰀄𰁘𰁌𰁅𰁒𰀄𰁉𰁚𰁉𰁖𰀒𰀄𰀄𰀸𰁌𰁅𰁘𰂫𰁗𰀄𰁛𰁌𰁝𰀄𰁘𰁌𰁉𰀄𰁊𰁍𰁖𰁗𰁘𰀄𰁑𰁓𰁚𰁉𰀄𰀄𰁗𰁌𰁓𰁙𰁐𰁈𰀄𰁆𰁉𰀄𰁘𰁓𰀄𰁐𰁓𰁓𰁏𰀄𰁊𰁓𰁖𰀄𰁅𰀄𰁇𰁓𰁑𰁔𰁅𰁒𰁝𰀄𰁛𰁍𰁘𰁌𰀄𰁛𰁓𰁖𰁐𰁈𰁛𰁍𰁈𰁉𰀄𰀄𰁇𰁅𰁔𰁅𰁆𰁍𰁐𰁍𰁘𰁝𰀄𰁅𰁒𰁈𰀄𰁉𰁜𰁔𰁉𰁖𰁍𰁉𰁒𰁇𰁉𰀒𰀄𰀄𰀥𰁒𰁈𰀄𰁘𰁌𰁅𰁘𰂫𰁗𰀄𰀸𰁖𰁅𰁒𰁗𰁓𰁇𰁉𰁅𰁒𰀒𰀸𰁖𰁅𰁒𰁗𰁓𰁇𰁉𰁅𰁒𰀄𰁌𰁅𰁗𰀄𰁑𰁓𰁖𰁉𰀄𰁉𰁜𰁔𰁉𰁖𰁍𰁉𰁒𰁇𰁉𰀄𰁈𰁖𰁍𰁐𰁐𰁍𰁒𰁋𰀄𰁈𰁉𰁉𰁔𰁛𰁅𰁘𰁉𰁖𰀄𰁅𰁒𰁈𰀄𰁌𰁅𰁖𰁗𰁌𰀑𰁉𰁒𰁚𰁍𰁖𰁓𰁒𰁑𰁉𰁒𰁘𰀄𰁛𰁉𰁐𰁐𰁗𰀄𰁘𰁌𰁅𰁒𰀄𰁅𰁒𰁝𰁓𰁒𰁉𰀒𰀄𰀄𰀻𰁉𰀄𰁅𰁐𰁗𰁓𰀄𰀄𰁌𰁅𰁚𰁉𰀄𰁘𰁌𰁉𰀄𰁐𰁅𰁖𰁋𰁉𰁗𰁘𰀄𰁅𰁒𰁈𰀄𰁑𰁓𰁗𰁘𰀄𰁈𰁍𰁚𰁉𰁖𰁗𰁉𰀄𰁊𰁐𰁉𰁉𰁘𰀄𰁍𰁒𰀄𰁘𰁌𰁉𰀄𰁛𰁓𰁖𰁐𰁈𰀐𰀄𰀄𰁗𰁓𰀄𰁛𰁉𰀄𰁇𰁅𰁒𰀄𰁈𰁉𰁐𰁍𰁚𰁉𰁖𰀄𰁉𰁜𰁅𰁇𰁘𰁐𰁝𰀄𰁘𰁌𰁉𰀄𰁗𰁉𰁖𰁚𰁍𰁇𰁉𰀄𰁓𰁙𰁖𰀄𰁇𰁙𰁗𰁘𰁓𰁑𰁉𰁖𰁗𰀄𰀄𰁒𰁉𰁉𰁈𰀄𰁛𰁌𰁉𰁒𰀄𰁅𰁒𰁈𰀄𰁛𰁌𰁉𰁖𰁉𰀄𰁘𰁌𰁉𰁝𰀄𰁒𰁉𰁉𰁈𰀄𰁍𰁘𰀒𰀄𰀄𰀥𰁒𰁈𰀄𰁛𰁉𰀄𰁓𰁔𰁉𰁖𰁅𰁘𰁉𰀄𰀄𰁍𰁒𰀄𰁉𰁚𰁉𰁖𰁝𰀄𰁑𰁅𰁎𰁓𰁖𰀄𰁓𰁍𰁐𰀄𰁅𰁒𰁈𰀄𰁋𰁅𰁗𰀄𰁅𰁖𰁉𰁅𰀐𰀄𰁗𰁓𰀄𰁛𰁉𰀄𰁇𰁅𰁒𰀄𰁗𰁅𰁚𰁉𰀄𰁓𰁒𰀄𰀄𰁑𰁓𰁆𰁍𰁐𰁍𰁞𰁅𰁘𰁍𰁓𰁒𰀄𰁅𰁒𰁈𰀄𰁈𰁉𰁑𰁓𰁆𰁍𰁐𰁍𰁞𰁅𰁘𰁍𰁓𰁒𰀄𰁇𰁓𰁗𰁘𰁗𰀄𰁛𰁓𰁖𰁐𰁈𰁛𰁍𰁈𰁉𰀒𰀴𰁙𰁘𰀄𰁘𰁌𰁉𰁑𰀄𰁅𰁐𰁐𰀄𰁘𰁓𰁋𰁉𰁘𰁌𰁉𰁖𰀄𰁅𰁒𰁈𰀄𰁝𰁓𰁙𰀄𰁇𰁅𰁒𰀄𰁗𰁉𰁉𰀄𰁛𰁌𰁝𰀄𰁑𰁓𰁖𰁉𰀄𰁅𰁒𰁈𰀄𰁑𰁓𰁖𰁉𰀄𰁇𰁙𰁗𰁘𰁓𰁑𰁉𰁖𰁗𰀄𰁌𰁅𰁚𰁉𰀄𰁐𰁉𰁅𰁖𰁒𰁉𰁈𰀄𰁘𰁌𰁅𰁘𰀄𰁘𰁌𰁉𰀄𰁖𰁍𰁋𰁌𰁘𰀄𰁑𰁓𰁚𰁉𰀄𰁍𰁗𰀄𰁊𰁖𰁉𰁕𰁙𰁉𰁒𰁘𰁐𰁝𰀄𰁘𰁌𰁉𰀄𰁉𰁅𰁗𰁍𰁉𰁗𰁘𰀄𰁑𰁓𰁚𰁉𰀒𰀄𰀄𰀸𰁌𰁅𰁘𰂫𰁗𰀄𰁛𰁌𰁝𰀄𰁘𰁌𰁉𰁝𰀄𰁇𰁅𰁐𰁐𰀄𰀸𰁖𰁅𰁒𰁗𰁓𰁇𰁉𰁅𰁒𰀒𰀄𰀸𰁖𰁅𰁒𰁗𰁓𰁇𰁉𰁅𰁒𰀞𰀄𰀻𰁉𰂫𰁖𰁉𰀄𰁒𰁉𰁚𰁉𰁖𰀄𰁓𰁙𰁘𰀄𰁓𰁊𰀄𰁓𰁙𰁖𰀄𰁈𰁉𰁔𰁘𰁌𰀒𰂋𰀄𰀄

www.deepwater.com


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Drill pipe, right now T

he largest drill pipe stocking distributer in the world, Champions Pipe and Supply delivers now. With NOV Grant Prideco as our primary pipe source, we feature a multitude of sizes and styles of drill pipe, heavy weight drill pipe, landing strings and more. We specialize in new, USA-made, critical-service products, including:

High-torque connections GPDS® HI-TORQUE ® eXtreme Torque ® TurboTorque ® UBD and completion pipe Landing strings Sour service drill pipe NS-1 compliant drill pipe For an up-to-date stock list , visit www.championspipe.com today. Send your inquiries to: Ed Mazurek, 281-606-1798, 713-248-7936, [email protected] Gerald Slayton, 281-606-1800, 713-882-2230, [email protected]

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International Edition Volume 71, Number 1 January 2011 Celebrating Over 50 Years of Trends, Tools, and Technology

60 GULF OF MEXICO Deepwater drilling outlook remains uncertain...................... 34 While some drillers remain positive about the deepwater Gulf, plans are still being stymied by a lack of regulatory clarity.

Survey of US GoM deepwater discoveries ............................. 40 Offshore’s annual survey shows the status of the latest deepwater discoveries in the Gulf of Mexico.

Offshore bidding model enhances performance ................... 46 Analyses of recent lease sales in the Gulf of Mexico suggest that bid outcomes can be highly uncertain and the associated results for E&P companies who compete in the bid environment are mixed at best.

DEEPWATER HORIZON AFTERMATH Drilling permits being reviewed, says Bromwich.................. 52 Return to normality hinges on BOEMRE’s proposed budget hike and future reforms.

GEOLOGY & GEOPHYSICS Using seismic-while-drilling technology to reduce uncertainty .......................................... 56 The sedimentary basins of the Gulf of Mexico (GoM) exhibit a wide range of different geological characteristics, especially in the presence of complex salt bodies.

Using gravity gradiometry to explore subsalt ....................... 60 Whether applied to licensing, frontier exploration, mature plays, prospect generation, or evaluation, gravity gradiometry imaging is a powerful de-risking and exploration tool.

CONTENTS

68 DRILLING & COMPLETION Analysis confirms effectiveness of gilsonite as offshore shale stabilizer ................................ 62 An independent evaluation has verified the effectiveness of gilsonite as an HSE acceptable and high-performance inhibition and fluid loss control additive for water-based fluids.

The Skarv FPSO turret mooring system: A 5,000-ton challenge ............................................................ 65 BP intends to develop the Skarv field using a turret moored new-build FPSO.

ENGINEERING, CONSTRUCTION & INSTALLATION New heavy lift vessel deploys in Gulf .................................... 68 Recently-completed catamaran heavy-lift vessel successfully performs first heavy lift operation.

New Topsides, Platforms & Hulls conference meets growing industry demand ........................................... 70 Engineering, design, construction, and installation of offshore production systems will continue to expand as the number of offshore installations increases worldwide.

PRODUCTION OPERATIONS The business case for investing in safety ............................. 71 Statoil deploys an automatic ID system to reduce human error in the event of an emergency.

Offshore (ISSN 0030-0608) is published 12 times a year, monthly by PennWell, 1421 S. Sheridan Road, Tulsa, OK 74112. Periodicals class postage paid at Tulsa, OK, and additional offices. Copyright 2011 by PennWell. (Registered in U.S. Patent Trademark Office.) All rights reserved. Permission, however, is granted for libraries and others registered with the Copyright Clearance Center, Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, Phone (508) 750-8400, Fax (508) 750-4744 to photocopy articles for a base fee of $1 per copy of the article plus 35¢ per page. Payment should be sent directly to the CCC. Requests for bulk orders should be addressed to the Editor. Subscription prices: US $101.00 per year, Canada/Mexico $ 132.00 per year, All other countries $167.00 per year (Airmail delivery: $234.00). Worldwide digital subscriptions: $101 per year. Single copy sales: US $10.00 per issue, Canada/Mexico $12.00 per issue, All other countries $14.00 per issue (Airmail delivery: $22.00. Single copy digital sales: $8 worldwide. Return Undeliverable Canadian Addresses to: P.O. Box 122, Niagara Falls, ON L2E 6S4. Back issues are available upon request. POSTMASTER send form 3579 to Offshore, P.O. Box 3200, Northbrook, IL 60065-3200. To receive this magazine in digital format, go to www.omeda.com/os.


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Two months ago, we had a process redesign. Last month? The I/O schedule changed…again. Today, skids showed up and didn’t match spec. And yet, our start-up isn’t changing.

Next time, design flexibility and adaptability into your project right from the start. Now, instead of a design freeze, you can make your I/O and marshalling decisions when you need to, right through construction and commissioning, with Emerson’s new I/O on Demand technology. So not only are last-second changes not a problem, there’s no need to build in the extra slack time that pushes out your project’s start-up. Less engineering. Fewer change orders. Shorter project cycles. With Emerson’s I/O on Demand technology, it’s possible. __________________________ EmersonProcess.com/,OonDemand

The Emerson logo is a trademark and a service mark of Emerson Electric Co. © 2010 Emerson Electric Co.


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International Edition Volume 71, Number 1 January 2011 COVER: With the advent of a new year, operators are looking to renew their exploration and production programs in the Gulf of Mexico. One key sign of renewed activity was the deployment of Versabar’s VB-10,000, its new catamaran heavy-lift vessel. The vessel recently completed its first heavy lift operation in the Gulf of Mexico. Photo by Peter Devine, courtesy Versabar Inc.

SUBSEA Operators elevate well integrity priority ................................................................... 74 Well integrity has been at the forefront of oil company concerns and the general public’s minds more than ever before over the past few months.

Wireless communication technologies enhance subsea production monitoring .................................................................... 76 Subsea wireless systems can help operators make effective real-time control decisions and perform effective troubleshooting measures.

FLOWLINES AND PIPELINES Survey assesses geohazards for record subsea pipeline ........................................ 78 Detailed route survey helps optimize the marine path of the proposed Galsi natural gas pipeline.

Mitigating deepwater pipeline buckling and axial stability ..................................... 82 Recent case study examines ways of improving the stability of high-pressure/high-temperature flowlines.

D E P A R T M E N T S _____________

Online .................................................... 6 Comment ............................................... 8 Data ..................................................... 10 Global E&P .......................................... 12 Offshore Europe .................................. 18 Gulf of Mexico ..................................... 20 Subsea Systems ................................. 22

Vessels, Rigs, & Surface Systems ...... 26 Drilling & Production .......................... 28 Geosciences ........................................ 30 Offshore Automation Solutions .......... 32 Business Briefs ................................. 104 Advertisers’ Index............................. 107 Beyond the Horizon .......................... 108

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PennWell 1455 West Loop South, Suite 400, Houston, TX 77027 U.S.A. Tel: (01) 713 621-9720 • Fax: (01) 713 963-6296

VICE PRESIDENT and GROUP PUBLISHER Mark Peters [email protected]

CHIEF EDITOR/CONFERENCE EDITORIAL DIRECTOR David Paganie [email protected]

SENIOR EDITOR/TECHNOLOGY & ECONOMICS Eldon R. Ball [email protected]

MANAGING EDITOR Bruce A. Beaubouef [email protected]

TECHNOLOGY EDITOR, SUBSEA & SEISMIC Gene Kliewer [email protected]

EDITOREUROPE

EDITORIAL ASSISTANT

Jeremy Beckman [email protected]

Priti Ubhayakar [email protected]

PRESENTATION EDITOR

POSTER EDITOR

Josh Troutman [email protected]

E. Kurt Albaugh, P.E. [email protected]

CONTRIBUTING EDITORS F. Jay Schempf (Houston) Larry O’Brien (Dedham, Mass.) Nick Terdre (Norway) Peter Howard Wertheim (Brazil) Gurdip Singh (Singapore)

SALES WORLDWIDE SALES MANAGER HOUSTON AREA SALES David Davis [email protected] Tel: (713) 963-6206 Bailey Simpson [email protected]

Available at

Offshore-mag.com Deepwater Horizon n incident Stay tuned to www.offshore-mag.com/index/deepwater-horizon-oil________________________________ s_________ pill-2010.html for news, videos, interviews, and analysis of the Deepwater Horizon incident and containment operations in the US Gulf of Mexico.

Upcoming webcasts ➤ Building an Emergency Spill Response System

Jan. 11, 2011: Following recent events in the Gulf of Mexico, offshore operators and service and supply companies are reformulating their emergency response plans and protocols to better prepare for possible spills and accidents. A select panel of industry experts will discuss the steps industry is taking now to improve response; best practices for cleaning up a spill or leak; relevant government regulations and policies; and what happens (scientifically) to the oil in the event that it is accidentally released into a marine environment. The panel is comprised by experts from industry, academia, and the consulting sectors, and will include Edward B. Overton, Ph.D., Professor Emeritus of Environmental Sciences, Louisiana State University; Lucian (Lou) Pugliaresi, President, Energy Policy Research Foundation (EPRINC); and David Salt, Operations Director, Oil Spill Response.

CUSTOM PUBLISHING Roy Markum [email protected] Tel: (713) 963-6220

PRODUCTION MANAGER Kimberlee Smith [email protected] Tel: (918) 832-9252 • Fax: (918) 831-9415

AUDIENCE DEVELOPMENT MANAGER Ron Kalusha [email protected] Tel: (918) 832-9208 • Fax: (918) 831-9482

SUBSCRIBER SERVICES Contact subscriber services for address changes Tel: (847) 559-7501 • Fax: (847) 291-4816 Email: [email protected]

REPRINT SALES Glenda Harp [email protected] Tel: (918) 832-9301 • Fax: (918) 832-9201

OFFSHORE EVENTS David Paganie (Houston) [email protected] Eldon Ball (Houston) [email protected] Gail Killough (Houston) [email protected] Niki Vrettos (London) [email protected] Jenny Phillips (London) [email protected]

CORPORATE HEADQUARTERS PennWell; 1421 S. Sheridan Rd., Tulsa, OK 74112 Member All Rights reserved Offshore ISSN-0030-0608 Printed in the U.S.A. GST No. 126813153 CHAIRMAN: Frank T. Lauinger PRESIDENT/CHIEF EXECUTIVE OFFICER: Robert F. Biolchini CHIEF FINANCIAL OFFICER: Mark C. Wilmoth

Publications Mail Agreement Number 40052420 GST No. 126813153

➤ Meeting the Challenges of Arctic Development

Jan. 27, 2011: Arctic oil and gas resources represent the next big chapter in offshore development. Yet, the development of these resources remains challenging in terms of engineering, construction and installation, and related logistics. Dr. Shawn Kenny, the Wood Group Chair in Arctic and Harsh Environments Engineering and Associate Professor at Memorial University in St. John’s, Newfoundland and Labrador, will present an overview of practical engineering solutions that will allow oil and gas operators to safely and efficiently work in Arctic offshore environments. He will be joined by G. Abdel Ghoneim, PE, PhD, Det Norske Veritas, who will provide an update on industry activities for these regions, including the latest on ship classification; fixed and floating drilling/production unit classification; third-party verification; environmental assessments/risk analysis; and ice/ship interaction.

View webcasts on demand ➤ Offshore’s Top 5 projects of 2010

The editors of Offshore have made their choices for winners of the Five Star Award – the top five offshore field development projects for 2010. The projects are selected on the basis on best use of innovation in production method, appli-cation of technology, and resolution of challenges, along with safety, environmental protection, and project completion time. http://www.offshore-mag.com/index/webcasts/ webcast-display/6454730782/webcasts/webcasts-offshore/ ________________________________________ live-events/offshore-top_5_projects0.html ____________________________

➤ Casing Drilling Update: Reducing NPT and Enhancing Reservoir Productivity Eric Moellendick, Director of Global Technology, Tesco Corp., presents an Offshore exclusive webcast on Tesco’s current casing drilling toolbox and the company’s newly introduced liner drilling system. The webcast includes recent case studies illustrating the advantages of the casing drilling process to miti mi tiga gate te or el elim imin inat atee NP NPT. T.

6 Offshore January 2011 • www.offshore-mag.com


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Advancing Reservoir Performance

14,000

How we drilled nearly feet of salt and used real-time data to eliminate NPT

©2010 Baker Hughes Incorporated. All Rights Reserved. 30249

A client contacted Baker Hughes to help them overcome key challenges related to wellbore quality and drilling efficiency in a Gulf of Mexico exploration well. They were having difficulty keeping wells vertical; and connection times in the salt—which averaged 27 minutes—were deemed unacceptable. Baker Hughes offered a fast, efficient solution. Building on our AutoTrak™ rotary steerable system and key logging technologies, including CoPilot™ drilling dynamics and ZoneTrak™ bit resistivity LWD, our rigsite experts maintained excellent verticality in the upper salt and delivered a smooth kickoff to the build. Our bit resistivity service successfully detected the salt base immediately after exit. And, thanks to our fast, accurate surveys and the AutoTrak system’s “on-the-fly” downlinking, connection times in the salt were reduced by an average of 10 minutes—helping deliver the vertical section 10 days ahead of the client’s AFE. If you want to find out how to improve efficiency and obtain better results on your next project, contact your Baker Hughes representative or visit us online. Start saving time while drilling. www.bakerhughes.com


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COMMENT

David Paganie • Houston

Spending on the rise

Our Tradition Runs

Exploration and production spend is back on trend, forecast to post consecutive yearly increases since the drop off in 2009. Driven by improving market fundamentals and recovering economies, much of the forecast spend – offshore – will be directed to regions where industry’s technological limitations and geopolitical endurance will be tested. Meanwhile, the shift to deepwater continues, led by Brazil, West Africa, and Australia. Spending in floating production and subsea systems is estimated to increase as a result. Infield Systems’ five-year forecast calls for $74 billion in development capex for floating production systems, a 90% increase from the previous forecast period. Development capex for subsea systems, Infield predicts, is expected to increase 49% from the previous five-year period to $74 billon. The International Energy Agency estimates that deepwater production will increase from 6% to 9% of total oil and from 22% to 29% of offshore supplies, while adding 2.8 MMb/d, by 2015.

Deep In-depth coverage of offshore oil and gas industry for more than 56 years Drilling and Completion Production Subsea Construction and Installation Transportation and Logistics Geology and Geophysics

Headlines for 2011 A number of important story lines to keep an eye on this year include the continuing rollout of new findings, operational mandates, lessons learned, and the pace (or lack thereof) of approving deepwater drilling permits in the Gulf of Mexico; the development of Brazil’s pre-salt reserves; the potential emergence of another rig building boom; and new technological advances in the design and deployment of floating liquefied natural gas facilities; among others. Despite the persistent uncertainty associated with deepwater drilling in the Gulf, major capital development projects are moving forward. Recent examples are Chevron’s $4-billion Big Foot and $7.5-billon Jack/St. Malo, and Shell’s Mars B.

Offshore automation solutions

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Beginning in this issue, it is my pleasure to introduce our new editorial column – “Offshore Automation Solutions.” In this first edition, Larry O’Brien, research director, ARC Advisory Group, discusses the elements and application of an ideal procedural automation strategy; the three primary categories of operational procedures: manual, prompted, and automated; and procedural automation to reduce the startup and shutdown of offshore platforms. His full report begins on page 32. In addition to the latest technological applications, trends, and analysis, stay with Offshore throughout 2011 for complete coverage of our international conferences. The lineup includes: • Offshore West Africa conference & exhibition – March 15-17, Accra, Ghana (www. ___ ______________ offshorewestafrica.com) _________ • Offshore Asia conference & exhibition – March 29-31, Singapore (www.offshoreasiaevent.com) ________ • Offshore India conference & exhibition – Sept. 14-16, Mumbai (www.offshoreoil__________ ______ india.com) • Deep Offshore Technology International conference & exhibition – Oct. 11-13, New Orleans (www.deepoffshoretechnology.com).

www.offshore-mag.com 8 Offshore January 2011 • www.offshore-mag.com

To respond to articles in Offshore, or to offer articles for publication, contact the editor by email ([email protected]).


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G L O B A L D ATA

Worldwide day rates

Worldwide offshore rig count & utilization rate

Year/Month

Dec 2008 – Nov 2010 Total fleet

Contracted

Working

850

100%

750

90%

650

80%

550

70%

450

60%

350 Dec 08 Mar 09 June 09 Sep 09 Dec 09 Mar 10 June 10 Sep 10

50%

Fleet utilization rate

Copyright © 2011 ODS-Petrodata Inc.

GoM drilling permits issued 100 90 70 60 50 40

30 20

21

18

15

14

July

Aug.

Sept.

9

10 May

June

Oct.

Nov.

$386,974 $387,605 $388,512 $389,356 $393,747 $386,496 $391,109 $398,266 $398,133 $403,444 $412,776 $404,466

$600,000 $630,000 $630,000 $592,500 $592,500 $592,500 $592,500 $592,500 $592,500 $650,000 $650,000 $650,000

$28,000 $28,000 $28,000 $28,000 $28,000 $28,000 $27,000 $25,000 $6,500 $10,000 $10,000 $10,000

$132,277 $129,531 $127,233 $123,335 $118,905 $116,205 $115,315 $115,693 $115,249 $114,750 $112,573 $110,604

$375,000 $375,000 $398,000 $398,000 $398,000 $398,000 $398,000 $398,000 $335,000 $335,000 $335,000 $335,000

$80,000 $83,000 $83,000 $83,000 $83,000 $83,000 $47,000 $47,000 $47,000 $47,000 $47,000 $47,000

$365,136 $368,951 $363,544 $365,240 $361,931 $360,212 $357,343 $351,744 $355,392 $356,034 $357,519 $362,844

$649,000 $649,000 $649,000 $649,000 $649,000 $649,000 $649,000 $649,000 $649,000 $649,000 $649,000 $649,000

Nov 2010

Oct 2010

Sept 2010

Aug 2010

July 2010

June 2010

May 2010

Drillships Semisub Jackups Dec 2009

Nov 2010

Oct 2010

Sept 2010

Aug 2010

100 90 80 70 60 50 40 30 20 10 0

Nov 2009

Percent

Source: Rigzone.com

July 2010

June 2010

May 2010

April 2010

March 2010

Feb 2010

Jan 2010

Dec 2009

$125,000 $125,000 $125,000 $125,000 $125,000 $125,000 $125,000 $125,000 $125,000 $125,000 $125,000 $125,000

Worldwide rig utilization

Drillships Semisub Jackups Nov 2009

Percent

Gulf of Mexico rig utilization 100 90 80 70 60 50 40 30 20 10 0

Maximum

Source: Rigzone.com

Source: BOEMRE

April 2010

0

13

March 2010

40

Jan 2010

Drilling permits

80

Average

Drillship 2009 Dec 2010 Jan 2010 Feb 2010 Mar 2010 April 2010 May 2010 June 2010 July 2010 Aug 2010 Sept 2010 Oct 2010 Nov Jackup 2009 Dec 2010 Jan 2010 Feb 2010 Mar 2010 April 2010 May 2010 June 2010 July 2010 Aug 2010 Sept 2010 Oct 2010 Nov Semi 2009 Dec 2010 Jan 2010 Feb 2010 Mar 2010 April 2010 May 2010 June 2010 July 2010 Aug 2010 Sept 2010 Oct 2010 Nov

Feb 2010

No. of rigs

Contracted fleet utilization

Minimum

Source: Rigzone.com



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Jeremy Beckman • London

GLOBAL E&P

North America Greenland’s government has awarded three new exploration concessions under its Baffin Bay bid round. Shell and its partners Statoil and GDF Suez picked up blocks 5 and 8, covering a total area of over 20,000 sq km (7,722 sq mi), and Maersk Oil won the 11,802-sq km (4,558-sq mi) block 9. In all cases, state oil company Nunaoil has a carried interest of 12.5% during the exploration phase. Maersk plans to establish a field research facility in the area, and will initially concentrate on acquiring new seismic data. Drilling may have to wait a few years. ••• Statoil was also a successful bidder in the latest lease sale offshore Newfoundland. Its haul included an extension of its license in the Flemish Pass basin, containing the Mizzen discovery; operatorship of an exploration license in the north of the basin; and a 50% stake in another exploration license in the Jeanne d’Arc basin (JDB), 250 km (155 mi) offshore Newfoundland. The company recently partnered Suncor Energy in the Ballicatters well in the JDB, and is lining up a further well in this basin during 2011-12 on its Fiddlehead permit. ••• Petronas Carigali has a new partner offshore Cuba, following the signing of a Transfer Agreement and a Joint Operating Agreement with Gazprom Neft for blocks 44, 45, 50, and 51 in the Gulf of Mexico. To date, 2D seismic has been acquired, and the partners expect to drill a first exploratory well some time this year.

South America PDVSA has contracted Technip to provide EPC management of Venezuela’s first offshore gas development. The Mariscal Sucre Dragon and Patao fields which will supply the gas are 25 mi (40 km) north of Paria peninsula, off the country’s northeast coast. Technip’s scope includes detail engineering both for the Dragon platform, to be installed in a water depth of 427 ft (130 m), and associated subsea facilities, construction management, and offshore transportation/installation. In the Gulf of Venezuela, a much larger gas project could take shape following a third successful well on the Perla structure in the Cardon IV block, operated by a joint company owned by Repsol and Eni. Results from the latest well have pushed up estimates of the field’s resources to over 14 tcf (2.5 BBboe). The partners already are working with PDVSA on an early production phase, slated to start up in mid-2013. ••• Brazil also continues to deliver. Anadarko Petroleum’s Itauna #1, its first well in block BM-C-29, intersected over 275 net ft (84 m) of oil and gas pay in two separate post-salt zones. Water depth was around 250 ft (76 m). In the Espirito Santo basin, Petrobras and Statoil found mid-density oil while drilling the Indra structure in license BM-ES-32. The location was 400 km (245 mi) north of the Peregrino field. And in Santos basin block BM-S-11, Petrobras and its partners encountered further light oil in Tupi West, 11 km (6.8 mi) northwest of the original Tupi discovery well. This could lead to the allocation of a further FPSO to the Tupi West area. Earlier, the consortium for this block and BM-S-9 in the same basin contracted Brazilian company Engevix Engenharia to build eight hulls for the fleet of FPSOs that will be used to develop the various fields in the concessions – Tupi, Iracema, Iara, Guara, and Carioca. The total value of the contract is around $3.5 billion. ••• Diamond Offshore’s Ocean Guardian has started drilling the Dawn/Jacinta 25/51 well for Desire Petroleum, the latest in its rolling campaign off the North Falklands basin. Its previous effort for Desire, on the Rachel North structure, was abandoned after hopes of an oil discovery were dashed. Rockhopper Exploration will then take the rig for one or two slots, in the same basin. In the South Falkland basin, Borders & Southern Petroleum is

hoping to take the deeper water semi Eirik Raude to drill its first wells, later this year, on the Darwin and Stebbing prospects. The rig is currently on development duty offshore Ghana.

West Africa First oil flowed last month from the deepwater Jubilee field, which spans two Ghanaian concessions. Kosmos Energy was responsible for the development, with partner Tullow Oil taking the helm during

The turret for the Jubilee field FPSO.

the production phase. Tullow expected production through the newbuild FPSO to rise steadily to 50,000 b/d, before surging to 120,000 b/d as new wells come on line. ••• Anadarko scored its second deepwater oil find offshore Sierra Leone, in the Sierra Leone-Liberian basin. The Mercury-1 well, in block SL-07B-10, encountered 135 net ft (41 m) of oil pay in two Cretaceous fan systems, in a water depth of 5,250 ft (1,600 m). Oil in the main objective was light and sweet. The location was 40 mi (64 km) southeast of the previous Venus discovery. ••• Alliance Engineering is providing jacket/topsides engineering and design for Chevron’s South Nemba Auxiliary (SNX) project off Angola. Chevron has ordered a multi-deck, four-pile jacket structure from EPC contractor DSME which will be bridge-linked to the SNA platform on the Nemba field. The new facility will include oil processing, separation, gas compression, and dehydration equipment.

Barents Sea Gazprom has awarded WorleyParsons a front-end engineering design (FEED) contract for the production vessel planned for phases 2 and 3 of the Shtokman gas-condensate project. This will have a ship-shaped hull, designed to withstand sea ice accumulations. WorleyParsons’ remit extends to design of the 70 MMcm/d (2.47 tcf/d) topsides process equipment, the marine systems, turret, and living quarters. CB&I was handed the FEED for the proposed LNG storage and loading facility at the port of Terriberka in the Murmansk region.

Mediterranean Sea Cooper Energy has taken an 85% operated interest in the Nabeul permit in the Gulf of Hammamet offshore Tunisia. The commitments include acquiring new seismic to mature prospects, and drilling of one offshore well. Cooper says its initial focus will be on the Alpha and Gamma oil prospects in the west of the concession. Both are thought to lie in the same Birsa sandstone produced in the nearby Birsa, Oudna, and Tazerka fields. •••



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Be master of the arctic Aker Solutions’ subsea technology and experience get you there Enter the arctic with Aker Solutions, the only company offering a full suite of technology to develop subsea oil and gas assets stranded in harsh environments. To succeed here, you need integrated solutions that overcome the challenges of long-distance tie-backs in remote parts of the world. We deliver, with world-leading subsea compression and superior complimentary technologies that include boosting, high-voltage umbilicals, high-bandwidth controls, HIPPS and pipeline Direct Electrical Heating (DEH) systems – everything over far reaches. For years Aker Solutions has led the way in an array of arctic solutions. We’re the natural You also gain the advantages of E2E Subsea, which integrates our technology, service and regional expertise Rule the arctic with Aker Solutions. Compression

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GLOBAL E&P

BG Egypt has delivered its first Oligocene gas discovery in the deepwater West Nile Delta area, 80 km (49.7 mi) northwest of Alexandria. The Hodoa find was drilled by the semisubmersible Pride North America in 1,077 m (3,533 ft) of water. BP’s partner in the concession is RWE Dea. ••• Preliminary reports suggest Noble Energy’s latest exploration well in the Levantine basin offshore Israel is a gas discovery. However, partner Delek Drilling cautioned against size estimates for the Leviathan prospect until further analysis is complete.

Black Sea GSP Offshore has installed a new drilling rig on TPAO’s Akcakoca platform in the Turkish sector. The modular rig, lifted on by the crane barge GSP Neptun, was to be used initially to tie two wells back to the platform, later to extend development drilling on the Akcakoca gas field.

Middle East The Emir of Qatar has officially opened the country’s newest offshore and marine shipyard, a joint venture between Keppel Offshore & Marine and Qatar Gas Trans-


port Co. The new facility already has a memorandum of understanding to provide services to Gulf Drilling International. ••• Pars Oil & Gas Co. claims to have discovered a large layer of heavy oil beneath the Ferdowsi gas field in the Persian Gulf. Foreign companies have expressed interest in participating in a potential development. New studies by the Iranian government also suggest the oil layer in the giant offshore South Pars field could be 2.5 times greater than previously thought.

East Africa/Indian sub-continent Anadarko ended the year by extending its pool of gas in Mozambique’s deepwater Rovuma basin. The well on the Lagosta prospect, drilled by the Belford Dolphin, encountered over 550 ft (167 m) of gas pay in Oligocene and Eocene sands. The location was to the south and southeast of the previous Barquentine and Windjammer finds. Next up for the rig was a well on the Tubarao prospect, 17.5 mi (28 km) to the southwest, also in Offshore Area 1. Location of Lagosta, Anadarko’s latest gas discovery off Mozambique.

Captains of Enterprise–Give your global energy perspective a whole new perspective. Our 2011 program. Register early. Space is limited. February 21-25, 2011. SMU James M. Collins Center Dallas, Texas Visit www.exed.cox.smu.edu/global or call 214.768.7676. In association with Maguire Energy Institute.

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GLOBAL E&P

••• To the north, off Tanzania, Ophir Energy notched a second successive gas discovery with the Chewa-1 well in block 4, 8 km (5 mi) northwest of the Pweza-1 success. Following completion of a third planned well, partner BG Group has the option to assume operatorship of this block plus blocks 1 and 3 from Ophir. ••• Japan Drilling Co. has agreed to provide its deepwater drillship for operations offshore Sri Lanka, starting this July. The operator is Cairn Lanka and the program comprises three firm and two optional wells.

Asia-Pacific Chevron has initiated the Gendalo-Gehem gas project in the Makassar Strait offshore East Kalimantan, Indonesia. There will be two separate hub developments, each based on a floating production unit (FPU), subsea drill centers, gas and condensate export pipelines, and an onshore reception facility. Up to 1.1 bcf/d will be produced, either for domestic use, or as feedstock for the Bontang LNG plant. PT Technip Indonesia has the FEED contract for the FPUs, with PT Worley Parsons FEED contractor for the subsea facilities and pipelines. ••• Total has taken an 85% operated interest in block SK317B, offshore Sarawak, Malaysia. The 700-sq km (270-sq mi) concession spans waters ranging in depth from 200-1,000 m (656-3,281 ft). Commitments include seismic acquisition and deep offshore exploration drilling. Offshore Borneo, Eni has found further gas with its latest well on the Jangkrik field in the Muara Bakau permit. It now estimates in-place resources at over 1.4 tcf.

••• BG Group’s first well as an operator offshore China has delivered gas. The Linshui 22-1-1 well was drilled 130 km (81 mi) offshore in the Qiongdongnan basin in the South China Sea, in a water depth of 1,338 m (4,390 ft). BG plans to drill a second well on its acreage in the area early this year.

Australia/New Zealand Woodside Energy has awarded the Pöyry-Peritus partnership a concept definition study for the Lady Nora development. Lady Nora is one of numerous hydrocarbon pools to the southwest of the Goodwyn A platform. Water depth is around 80 m (262 ft). Peritus will provide study management and subsea and marine engineering, with Pöyry’s responsibilities including topsides facilities and flow assurance. Woodside operates the development on behalf of the North West Shelf venture. ••• Chevron Australia has contracted the Clough Sea Trucks joint venture for construction services for the Gorgon project. This covers installation of 90 km (56 mi) of 20-in. (51-cm) pipeline, offshore and onshore, from Barrow Island to the Dampier Bunbury natural gas pipeline. The derrick lay barge Java Constructor and shallow water lay barge Clough Challenge will handle offshore installations. ••• Oil Search has agreed farm-in terms for two new exploration licenses offshore Papua Guinea. License PPL 276 is west of the Pandora and Pasca gas fields in the Gulf of Papua, while PPL 312 is in the northern part of the Gulf, east of the Uramu gas field. Oil Search’s strategy is to build up a pool of proven or potential gas accumulations that could support commercialization.

______


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OFFSHORE EUROPE

Statoil turns to compression for Norway hubs Statoil has committed to compression for three of its main gas production centers on the Norwegian shelf. It aims to prolong output from existing fields under development, and to prepare the facilities for new roles as regional hubs. The largest project in monetary terms is a subsea compression system for the Åsgard field complex on the Haltenbanken in the Norwegian Sea, where water depths range from 240-310 m (787-1,017 ft). Aker Solutions has the $552-million equipment contract, which includes a subsea compressor manifold station and template, three compressor trains, electrical control systems, HV power distribution, and topside tie-ins. In the same region, Statoil has put a tag of $368 million on its plan to install a new compressor module on the Kristin platform, designed to introduce lower pressure production. This, the company says, will lift reserves recovery from the Kristin and Tyrihans fields by up to 115 MMboe, and will extend life from these fields and others in the area through 2029-2034. The new equipment should be installed during summer 2013, entering service the following spring. Finally, in the North Sea, Bergen Group Rosenberg will build and install a compressor module on the Kvitebjorn platform. Statoil describes this as a “pre-compression” project, allowing for production with reduced wellhead pressure. Fabrication is under way on the gas turbine-driven compressor, which should be installed between 2012-2014. Gas from Kvitebjorn is piped to Kollsnes in western Norway. Bergen Group’s $161-$242-million contract includes an option for tie in of a condensate pipeline to the Valemon platform, also currently under construction.

UK majors add platforms Major operators in the UK central North Sea have embarked on incremental developments. Total plans to install a new platform on the West Franklin field in blocks 29/5b and 29/4d in the high-pressure/high-temperature gas-condensate region. The aim is to produce 85 MMboe of fresh reserves via a new platform and initially three wells, which will be linked to the existing Elgin/Franklin production facilities. Total estimates the cost at $1 billion, and expects to deliver 40,000 boe/d when the platform starts up in 2013. Apache Corp. has ordered a new satellite oil production platform for mid-2012 for the Forties field, which will be bridge linked to the Forties Alpha platform. OGN Group’s Hadrian Yard close to Newcastle in northeast England, will build the facility under a $242-million contract. It will provide Apache with 18 new slots for drilling development wells, along with HP

Total’s Franklin development in the UK central NorthSea.

gas compression for artificial lift and dehydration. Apache estimates Forties has a further 173 MMboe of remaining proved reserves, and is looking to maintain daily oil output at around 60,000 b/d through 2013 and beyond. AMEC, which used to run Hadrian, will manage modifications to Forties Alpha.

Hess extends South Arne In the Danish North Sea, Hess and its partners DONG Energy, Noreco, and Danoil have approved a Phase III development of the South Arne field in license 07/89. The proposed scheme, designed to extract a further 15 MMboe, involves drilling and stimulation of 11 new wells, and adding two new wellhead platforms to the north and alongside the existing South Arne facility. One of the first contracts to be awarded was a pipeline bundle, which Subsea 7 will fabricate and install in 2012, linking the two new platforms. The field is in a water depth of 60 m (197 ft). DONG recently made a new oil discovery in the Solsort prospect in license 4/98, drilled by the Maersk Resolute. Three side tracks also were drilled to define the limits of the find, all with positive outcomes.

Apollo shines for Lundin Lundin Petroleum says its recent oil discovery well on the Apollo prospect in the Norwegian North Sea could be in the range of 15-65 MMboe. Well 16/1-4 was drilled by the Transocean Winner on license PL338 to target an extension of the Jurassic reservoir associated with Det norske oljeselskap’s Draupne find. But results suggest only a limited part of Draupne extends into the license. At the Palaeocene (Heimdal formation) and Cretaceous levels, two oil columns were encountered. The well also penetrated 60 m (197 ft) of good-quality Cretaceous sands be-

low the oil-water contact, suggesting potential up-dip of the discovery. It is not clear, however, whether Apollo could feature in Lundin’s plan for the Greater Luno Area development, which is expected to go forward later this year.

Studies re-assess Irish fields Providence Resources has become operator of the Barryroe oil discovery in the North Celtic Sea off southern Ireland. The company says the partners will commission a new 3D seismic survey early in 2011, the results of which will help preparations for an appraisal/ pre-development well. Discussions are under way with other consortia on the Irish shelf concerning a rig slot. Independent analysts have estimated the field’s recoverable contingent resources at 59144 MMbbl. Barryroe’s crude is waxy, and its reservoir architecture is complex, but Providence says this could be addressed via horizontal, artificially lifted well completions. Providence also operates the 1981 Spanish Point discovery in 400 m (1,312 ft) water depth, 170 km (105 mi) off western Ireland in the Porcupine basin. Newly interpreted 3D seismic and wide-ranging modeling studies suggest 100-200 MMboe could be recoverable. Field development could involve drilling six to 14 fracturestimulated wells, with potential plateau production of 30,000 b/d of oil and 250 MMcf/d of gas. In the St. George’s Channel basin separating Ireland from Wales, the company has signed an optional agreement whereby Star Energy would farm into 50% of Standard Exploration License SEL 1/07. The permit is in 90 m (295 ft) water depth, and contains the mapped extension of Marathon’s 1994 Dragon gas discovery offshore west Wales, and the deeper-lying Orpheus and Pegasus prospects. Star would earn the farm-in right by conducting subsurface studies on Dragon, then participating in an appraisal well.



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Global Energy and Mediterranean Opportunities Ravenna March 23-25, 2011 www.omc.it Established by OMC is organised in Association with

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Bruce Beaubouef • Houston

GULF OF MEXICO

Chevron sanctions Big Foot project in the deepwater Gulf Chevron Corp. says it has sanctioned development of its $4-billion Big Foot project in the deepwater U.S. Gulf of Mexico. “Sanctioning Big Foot underscores our commitment to the Gulf of Mexico and will contribute to future U.S. energy supply,” said George Kirkland, vice chairman, Chevron Corp. “This project is another example of Chevron’s disciplined approach to advancing our enviable queue of major capital projects.” Big Foot will be Chevron’s sixth operated facility in the deepwater Gulf of Mexico and is located approximately 225 mi (360 km) south of New Orleans, in water depths of 5,200 ft (1,600 m). The development will use a dry tree extended TLP with an on-board drilling rig and have production capacity of 75,000 bbl of oil and 25 MMcf of natural gas per day. First oil is anticipated in 2014. “We have industry leading expertise in developing deepwater projects of this type and have repeatedly proven that we can do so safely,” said Gary Luquette, president, Chevron North America Exploration and Production Co. Discovered in 2006, the Big Foot field lies in the Walker Ridge area and is estimated to contain total recoverable resources in excess of 200 MMboe. Primary pay sands are Middle to Upper Miocene ranging from 19,000 to 24,000 ft (5,800 to 7,300 m) and lie below a salt canopy ranging from 8,000 to 15,000 ft (2,400 to 4,500 m) thick. Three exploration and appraisal wells with multiple side tracks have been drilled safely and successfully in the field to define the Big Foot structure. Chevron, through its subsidiary Chevron U.S.A. Inc., has a 60% working interest in the Big Foot project.

BOEMRE issues guidance regarding permit standards The US federal Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) has released additional information about how to comply with the recently issued rules and previous guidance. The new publication addresses the Drilling Safety Rule (or Interim Final Rule), NTL-6 (including Worst Case Discharge calculations), and NTL-10, as well as further information on BOEMRE’s inspections of BOP testing, Oil Spill Response Plans (OSRP), and the manner in which environmental assessments will be conducted for deepwater drilling plans. The actual publication is online at http:// ____ www.boemre.gov/ooc/press/2010/press 1213.htm. ______ “As we continue to strengthen oversight and safety and environmental protections, we must ensure that the oil and gas industry has clear direction on what is expected,” said BO-

Discovered in 2006, the Big Foot field lies in the Walker Ridge area and is estimated to contain total recoverable resources in excess of 200 MMboe.

EMRE Director Michael R. Bromwich. “Following discussions with members of the oil and gas industry, it is clear that this information will assist in their implementation of the stronger safety and environmental standards we have put in place. We remain committed to working with industry to provide additional guidance on these and other issues.”

Energy XXI buys shallow GoM interest from ExxonMobil Energy XXI says it has bought certain shallow water Gulf of Mexico interests from ExxonMobil for $1.01 billion. The properties include nine fields generally located between Energy XXI’s existing South Timbalier and Main Pass operations in water depths of 470 ft (143 m) or less. The properties produce approximately 20,000 net boe/d, about 53% of which is oil. Offshore leases included in the purchase total 130,853 net acres. Reserve estimates for the acquired properties were prepared on Nov. 16, 2010, by Netherland, Sewell & Associates, Inc., independent oil and gas consultants employed by Energy XXI. The properties are estimated to contain net proved and probable reserves of 66 MMboe, 61% of which is oil. Proved reserves are estimated at 30.1 MMbbl of oil and 116.1 Bcf of natural gas, or a total of 49.5 MMboe, 68% of which are proved developed. “With this acquisition, we are gaining access to production, infrastructure and extensive acreage complemented by seismic data and field studies,” said John Schiller, chairman and CEO of Energy XXI. “As operator of 94% of the assets being acquired, we would have a portfolio of drilling and recompletion opportunities that we can pursue while analyzing the potential for higherimpact exploration prospects.”

The deal is expected to enable Energy XXI to become the third-largest oil producer on the Gulf of Mexico shelf, with interests in seven of the top 11 oil fields on the shelf. Estimated proved plus probable reserves would increase 72% to 158.1 MMboe from 92.1 MMboe at the company’s June 20, 2010 fiscal year end. Production would increase to approximately 46,000 boe/d, up more than 77% from the 25,900 boe/d average in the most recent fiscal quarter ended Sept. 30, 2010, with oil representing 63%.

Gulf’s fixed-platform market will be strong, says report The outlook for the fixed platform installation market looks strong across the fiveyear period to 2014, according to a new Infield Systems report. Infield sees capex over the time exceeding $80 billion with 1,651 platforms to be installed. Asia is expected to see the most capex, and the Gulf of Mexico to see the largest number of installations. Projects such as gas storage in the United Kingdom and deep gas in the shallow waters off the Louisiana GoM coast are examples of new technology and adaptation of fixed platforms to new ways of extracting hydrocarbons. Along with the more conventional use of piled platforms, these regions are expected to be more active in the fixed platform market as concerns over energy security and production rates create development opportunities in long established fields. Although only representing 2% of the market in platform installations, there is a large growth in capex for gravity-based platforms. These large fixed projects across the globe, designed to withstand environmentally harsh conditions, are attracting investment which provides further evidence of a promising outlook for the fixed platform market.



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SUBSEA SYSTEMS

Gene Kliewer • Houston

Schematic of the Vega production installations.

Subsea production under way at Vega Statoil has kicked off production from the Vega gas and condensate field off Norway’s west coast. Vega has three seabed templates that send gas and condensate to the Gjøa platform. At full capacity, the Vega field will deliver 7 MMcm/d (247 MMcf/d) of gas and 3,900 cm/d (24,500 b/d) of condensate. At start-up, four wells were online. The final two are scheduled online in April. The project was completed on time and budget at a cost of NOK 7.6 billion ($1.267 billion). The Vega field consists of two licenses, Vega and Vega Sør. “The Vega field is what we call a technology-qualifying field. We have carried out 39 technology qualifications. This means that the equipment has been tested and designed to be used in new areas. This was done simultaneously with the development,” said Vega project coordinator Helge Hagen. Vega by the numbers: • Vega comprises 1.4% of Statoil’s total own production, and 2% of its total oil and gas production on the Norwegian shelf • Recoverable reserves are 18 bcm (635.6 bcf) of gas and 26 MMbbl of condensate • The Vega discoveries were made in 1982 and 1987 • The partners in Vega are Statoil (60%) and Petoro (40%) • The partners in Vega South are Statoil (45%), Bayerngas Norge (25%), Idemitsu Petroleum Norge (15%), and GDF SUEZ E&P Norge (15%) • FMC supplied underwater equipment and structures • Heerema did the heavy lifts in connection with the subsea structure installation • Subsea 7 handled the laying and connection of pipelines and cables • Dolphin Drilling completed clean-up of wells using Bideford Dolphin.

Ormen Lange subsea systems on order Elsewhere in the North Sea, Norske Shell has awarded a $95-million contract to FMC Technologies to supply the Ormen Lange development with subsea systems. The contract covers one eight-slot manifold, four pipeline end modules, control systems, and connection equipment. Ormen Lange is the North Sea’s deepest subsea development at 1,000 m (3,300 ft).

Petrobras, FMC to develop technology At one of the other major subsea development areas in the world, Petrobras has signed a memorandum of understanding with FMC Technologies Inc. to develop future subsea technology for projects offshore Brazil. The agreement includes the development of “innovative and cost effective subsea production systems to address the challenges associated with Petrobras’ pre-salt oil and gas fields. It also includes the design of subsea processing technologies that can increase re-

Subsea structures on the way to Vega. Photo by Andre Osmundsen/Statoil.

covery rates at Petrobras’ maturing oil and gas fields,” according to FMC.

Clariant joins deepwater Brazil action Clariant has won a contract to supply chemicals for pre-salt application from Petrobras. The agreement covers the chemical package and services for the Petrobras FPSO Capixaba, which operates off the Espírito Santo. Production currently is based on post-salt and pre-salt reserves, with pre-salt production having started this past July.

Acergy to run Capixaba pipe Petrobras also awarded Acergy S.A. a contract for subsea pipeline work at the Sul-Norte Capixaba project. Acergy will install an 18-in., 150-km (93-mi) igid gas pipeline to link the Camarupim field gas pipeline to the Parque das Baleias complex. Acergy’s charge includes the associated diving, construction and pre-commissioning activities. Total contract value is approximately $240 million, of which Acergy’s share is approximately $190 million. Engineering is under way with offshore installation scheduled to commence late 2011, using the Acergy Polaris and Acergy Harrier.

Expro awarded test tree contract Switching to the India Ocean, Expro has been awarded a subsea contract worth $4 million. State-owned Oil & Natural Gas Corp. Ltd has awarded Expro a three-year subsea test tree contract. The award includes mobilization of one set of subsea test tree equipment with accessories for 400 m (1,312 ft) of water and one firm and one optional set of subsea test tree equipment with accessories for 300 m (984 ft) water depth. Expro also will provide personnel for the operation.

Decommissioning tool designed for subsea use Seanic Ocean Systems has developed a subsea drill to support the growing platform decommissioning and salvage market. Seanic’s system combines technology with standard ROV interface. “The drill is hydraulically powered and operated through the ROV’s valve pack and allows for the option to be mounted either by magnet or sticky feet (vacuum created from suction cups),” said Andy Guinn, VP of Operations. “The drill was developed to cut holes into any flat or tubular surfaces as small as a 10-in. diameter. It will accept up to a 4-in diameter annular cutter and has a stroke of over 13-in. while cutting through steel or grout.” Seanic has delivered two of the tools to date.



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VESSELS, RIGS, & SURFACE SYSTEMS

Bruce Beaubouef • Houston

Deepwater market buoys vessel demand Offshore service vessels (OSV) are becoming larger, more specialized, and more technically sophisticated as a result of the rising demand for more complex deepwater field developments, including those in the Gulf of Mexico, according to a recent study by Germanischer Lloyd. The study further noted that there are about 2,500 OSVs worldwide and that the number is projected to rise from now through 2020. In addition to upstream oil and gas demand, the call for OSVs will grow to meet the offshore wind industry plans. All this has led to an expanded definition of OSV which now refers to “not only traditional supply boats, but also anchor handling tug/ supply ships, well stimulation ships, and standby ships” and even those “built to carry hazardous and noxious substances, to fight fires, or to occasionally recover oil,” said Stephen Gumpel, area manager North and Central America at Germanischer Lloyd.

Dockwise Ltd. says it will move forward with plans for a newbuild vessel to serve the emerging demand for ocean transports of up to and above 100,000 metric tons (110,213 tons).

the maritime transport industry, and is expected to require a total investment of approximately $200 million. Dockwise has applied for a patent on the design of the vessel. Dockwise says that the majority of its revenues originate from the oil and gas industry, and current trends for projects and equipment in this market are distinctly moving towards greater scale and size for premier projects: • Exploration and production is shifting from shallow water in traditional areas to deepwater and remote areas • Industry demand is for larger, heavier equipment, in single transportable modules • Plant and equipment is increasingly constructed in dedicated, low cost environments ahead of transportation. With the company’s existing backlog in combination with projects on the horizon, it is expected that the vessel will be occupied when it will come out of the shipyard in the latter part of 2012. Dockwise is in the process of negotiating with selected first-rate shipyards for construction of the new vessel.

Arctech to build icebreaker supply vessels Versabar’s VB-10,000 completes its first heavy lift operation in the Gulf of Mexico. Photo by Peter Devine, courtesy Versabar Inc.

VB-10,000 completes heavy lift assignment in Gulf Versabar Inc. says that the VB-10,000, its new catamaran heavy-lift vessel, has successfully completed its first heavy lift operation in the Gulf of Mexico. On Oct. 7, tugs towed the VB-10,000 through Aransas Pass, Texas, and into the Gulf of Mexico. Just over 48 hours later, on Oct. 9, the vessel used its hook-height systems to bring up a 1,530ton topside. Consisting of twin 240-ft (73-m) tall gantries mounted on custom-built barges, the vessel lifts with four independent blocks that can be controlled either separately or in synchronization. Versabar says this rapid deployment testifies to the high level of engineering that went into the building of the new lift system, and builds on its proven offshore lift designs, including the Versatruss and the Bottom Feeder concepts (see related story on p. 68).

Dockwise to build new “super vessel” Dockwise Ltd. says its board of directors has approved the commissioning of a newbuild vessel to serve the emerging demand for ocean transports of up to and above 100,000 metric tons (110,213 tons). The decision is subject to approval by a special general meeting of shareholders to authorize the proposed $100-million rights issue to part-finance the investment. As announced in August, Dockwise has been studying the feasibility of investing in a new semisubmersible monohull vessel, bigger than its current largest vessel, the Blue Marlin. This so-called “Type 0” vessel will have a deck size of 275 x 70 m (902 x 229 ft), a first for

Arctech Helsinki Shipyard Oy has an order from Sovcomflot for two newbuild icebreaking supply vessels. The $200-million contract calls for delivery of both vessels during spring 2013. Arctech Helsinki Shipyard Oy will build the new vessels for Sakhalin-1 Arkutun-Dagi gas field where they will supply the Exxon Neftegas platform. Both vessels will be similar measuring 99.2 m (325 ft) in length and 21.7 m (71 ft) in breadth. Their four engines have the total power of 18,000 kW and the propulsion power of 13,000 kW. As multipurpose vessels, these will be able to carry various type of cargo and they are equipped for oil combating, fire fighting, and rescue operations. Both vessels will be able to operate in 1.7 m (5.6 ft) of ice and temperatures to -35º C. Arctech is a joint venture of STX Finland and Russia’s state-owned United Shipbuilding Corp.

Pride orders new drillship Pride International Inc. has contracted Samsung Heavy Industries Ltd. to build a fifth ultra-deepwater drillship for $600 million. The vessel will be built in Geoje, South Korea, with a mid-2013 delivery target. The new drillship, to be named at a later date, is based on an SHI proprietary hull design measuring 750 ft (229 m) long and 140 ft (43 m) wide. The rig is designed for drilling in water depths of up to 12,000 ft (3,658 m), with a total vertical drilling depth of 40,000 ft (12,192 m), and will offer a pay load in excess of 20,000 metric tons (22,046 tons) and a 1,250-ton hoisting system. The rig will be equipped with dynamic positioning in compliance with DPS-3 certification, six 5.5 MW thrusters, expanded drilling fluids capacity, a 15,000 psi subsea well control system and upgraded system handling, and living quarters for up to 200 personnel.



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Eldon Ball • Houston

DRILLING & PRODUCTION

Value of independents in GOM E&P In the wake of the Macondo spill and the increase in operating costs and government regulations, the offshore operators most vulnerable to sticker shock at the rising prices and bureaucratic obstacles are the independents. Independents are less able to absorb higher costs, have fewer resources to deal with the changing regulatory climate, and stake a larger percentage of their profitability on individual projects. At the same time, their contribution to the E&P vitality of the Gulf of Mexico is mostly overlooked, particularly by high-level economists and policy makers. A recent study by IHS Global Insight (USA), Inc. examines the role of the independent operators in the GoM, and has some surprising revelations. The authors analyzed the economic contribution of the independents and potential loss as a result of policies that effectively prevent them from participating in future development in the offshore Gulf of Mexico and, in particular, in the deepwater.

Deepwater activity Most of us would think of independents as primarily shallow-water operators, with a sprinkling of them in deepwater. But on the contrary, the study noted that: • Independents are the largest shareholder in 66% of the 7,521 leases in the entire Gulf of Mexico and in 81% of the producing leases • In the deepwater portion of the Gulf of Mexico, independents are the largest shareholder in 52% of all leases and in 46% of the producing leases. They operate over half of the developing and producing deepwater fields. • Independents have drilled 1,298 wells in the deepwater, and they currently account for over 900,000 boe/d • Independents are responsible for an average of 70% of farm-ins – partnerships formed following the original lease agreement that enable prospects to be drilled and oil and gas produced.

Financial impact Their analysis for the 2009–2020 forecast period indicates that the exclusion of the independents from the offshore GoM would have some debilitating effects, including the following: Lost jobs in the four-state Gulf region (Alabama, Louisiana, Mississippi, and Texas) – direct, indirect, and induced: • 2009 – 202,502 • 2015 – 289,716 • 2020 – 300,974. Additionally, 40,777 construction-related jobs would be lost in the four-state Gulf region dur-

Oil and natural gas drilling and support services – deepwater expenditures. Deepwater wells drilled Independents Majors Total Avg. Cost (000) Drilling Independents Majors Total Support Services Independents Majors Total Drilling & Support Independents Majors Total

2009

2015

2020

62 81 143 $ 76,689

102 55 157 $ 89,825

114 49 164 $ 100,026

$ 4,754,713,673 $ 6,211,803,347 $10,966,517,019

$ 9,156,233,991 $ 4,930,279,841 $14,086,513,833

$11,450,169,057 $ 4,907,215,310 $16,357,384,368

$ 5,698,106,416 $ 7,444,300,317 $13,142,406,733

$11,479,782,309 $ 6,181,421,243 $17,661,203,552

$14,168,712,541 $ 6,072,305,375 $20,241,017,916

$10,452,820,088 $13,656,103,664 $24,108,923,752

$20,636,016,300 $11,111,701,085 $31,747,717,385

$25,618,881,599 $10,979,520,685 $36,598,402,284

Oil and natural gas drilling and support services – shallow-water expenditures. Shallow water wells drilled Independents Majors Total Avg. Cost (000) Drilling Independents Majors Total Support Services Independents Majors Total Drilling & Support Independents Majors Total

2009

2015

2020

122 8 130 $ 6,685

103 7 110 $ 7,830

90 7 96 $ 8,719

$ 812,422,849 $ 55,079,515 $ 867,502,364

$ 805,072,103 $ 54,581,159 $ 859,653,262

$ 781,279,822 $ 58,806,008 $ 840,085,830

$ 973,617,376 $ 66,007,958 $ 1,039,625,334

$ 1,009,372,684 $ 68,432,046 $ 1,077,804,731

$ 966,774,303 $ 72,767,958 $ 1,039,542,261

$ 1,786,040,225 $ 121,087,473 $ 1,907,127,698

$ 1,814,444,787 $ 123,013,206 $ 1,937,457,993

$ 1,748,054,124 $ 131,573,966 $ 1,879,628,091

ing 2009–20. This activity includes construction of rigs, platforms, pipelines, and production facilities. Lost taxes and royalties to the federal government: • 2009 – $7.34 billion • 2015 – $10.13 billion • 2020 – $9.98 billion. Lost state and local tax revenues in the four-state Gulf region: • 2009 – $3.18 billion • 2015 – $4.59 billion • 2020 – $4.68 billion Altogether, more than $147 billion in federal, state, and local revenues would be lost in a 10-year period if independents are excluded from the Gulf of Mexico. These estimates only include revenues collected from the four-state Gulf region.

Deepwater impact The study found that loss of exploration and development by independents in deepwater areas alone would also make a signifi-

cant difference in the economy of the region. Their study found, for example, that within the deepwater, the exclusion of the independents would mean the following: Lost jobs in the four-state Gulf region – direct, indirect, and induced • 2009 – 121,298 • 2015 – 230,241 • 2020 – 265,113. Lost taxes and royalties to the federal government: • 2009 – $3.64 billion • 2015 – $7.26 billion • 2020 – $8.33 billion. Lost state and local tax revenues in the four-state Gulf region: • 2009 – $1.63 billion • 2015 – $3.35 billion • 2020 – $3.94 billion. Altogether, more than $106 billion in federal, state, and local revenues would be lost in a 10-year period if independents are excluded from the deepwater, according to the study.



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GEOSCIENCES

Gene Kliewer • Houston

Research & Development leads the way The business of petroleum geosciences research and development has been in the news quite a bit lately. First, Schlumberger has opened a new research and geoengineering center in Rio de Janeiro. The Brazil Research and Geoengineering Center aims to integrate geosciences with engineering to improve hydrocarbon production and recovery from the complex deepwater reservoirs and pre-salt carbonates offshore Brazil. The new center includes a Geoengineering Research Center, a Geoengineering Technology Center, and a GeoSolutions Hub in addition to a number of reservoir laboratories. The Research Center, designed to work with both customers and academia, will conduct research on pre-salt formations and study their optimal development. The Geoengineering Technology Center will pursue geoscience workflows using Schlumberger’s Ocean application development and Petrel seismic-to-simulation software. Regional solutions to the integration of data from seismic and other techniques will be developed in the WesternGeco GeoSolutions Hub while three reservoir laboratories have facilities to test and evaluate reservoir rocks and fluids. The Brazil Research and Geoengineering Center covers 10,000 sq m (107,639 sq ft) and when fully staffed, up to 300 scientists, engineers and technical staff will work in multidisciplinary teams. The new facility is near the leading academic expertise of the Federal University of Rio de Janeiro, and is located on the same campus as Petrobras’ CENPES Research Center. “We are very excited to be opening this new center here in Rio de Janeiro,” said Ana Zambelli, Brazil GeoMarket manager, Schlumberger. “Future oil and gas production will increasingly lie in technically complex environments such as pre-salt carbonates and deepwater areas and we expect this facility, the first multinational research center in Brazil, to play an important role in responding to these and other demanding technical challenges.” Geotrace and BP have teamed to further develop POCS (Projection Onto a Convex Set) technology for use in seismic data processing for the oil and gas industry. BP originally developed POCS technology to interpolate – or reconstruct – data. POCS technology uses information surrounding data sets that may not be complete to reconstruct that missing data. “By providing missing information, POCS’ primary advantage is that it helps minimize risk in assessing a reservoir,” said Bill Schrom, CEO of Geotrace. “The technology opens doors that were previously closed by allowing geoscientists to build missing data from the information they already have.” “Ideally, geoscientists acquire all the data they need to help them understand reservoir formations. However, in some cases, certain valuable information may be missed in initial data acquisition. This is where POCS plays a valuable role in reconstructing missing data and eliminating the cost of acquiring new data to fill in the gaps,” Schrom explained. POCS technology is commonly used in many fields where data are corrupted or missing, such as Synthetic Aperture Radar (SAR) and Magnetic Resonance Imaging (MRI). CGGVeritas has signed a term sheet with Petrovietnam Technical Services Corp. to create a joint venture to operate 2D and 3D marine seismic vessels, primarily in Vietnamese waters. The joint venture will provide seismic data acquisition services for oil and gas clients operating in Vietnam and the region. “Strengthening long-term relationships with our clients is an important priority for CGGVeritas,” says Jean-Georges Malcor, CEO. “This marine joint venture with Petrovietnam further materializes the well established long term cooperation between our two companies that is founded on technology and a deep knowledge of the local geological content. The full breadth of CGGVeritas will support this joint venture focusing on developing seismic marine acquisition and

Carnarvon basin seismic dataset available. A large-scale 3D multiclient seismic dataset covering more than 30,000 sq km (11,583 sq mi) of the Carnarvon basin offshore northwestern Australia is available from Spectrum ASB. The Spectrum subsidiary says most hydrocarbons in the basin are from Upper Jurassic Dingo claystone, plus some other possible strata. In the outboard Rankin Platform, giant gas accumulations as well as oil and gas accumulations along the inboard eastern Gipsy-Rose-Lee trend are sourced from a delta-based Triassic to Middle Jurassic sequence. The oil reservoir is primarily in the Windalia sandstone of the Muderong shale and the Lower Cretaceous Barrow Group. Late Cretaceous and middle Miocene faulted anticlines provide structural traps. A range of plays show within this basin, including rollover anticlines and fault blocks associated with antithetic faults, stratigraphic traps, pinchouts and onlap plays.

processing solutions dedicated to the Vietnamese offshore exploration challenges.” A new marine seismic company is in the midst of forming. After a thorough strategic review of current business model and potential new business opportunities, Dolphin Interconnect Solutions ASA decided the future of the offshore seismic market is promising, with anticipated strong growth in demand for seismic services. Dolphin proposes to raise new equity of approximately NOK 360 million ($60 million) in a private placement to facilitate its entrance into the marine seismic industry. The company says total investments in connection with establishing a marine seismic division within Dolphin to be in the area of NOK 800 million ($133.6 million). Dolphin plans to offer a full range of marine geophysical services, including contract seismic, multi-client, and processing partnerships. “The outlook in the offshore market looks promising and we expect strong growth in demand for seismic services,” says Chairman of the Board of Dolphin Atle Jacobsen. “The agreement with GC Rieber Shipping will secure a high grade of vessel flexibility and low operational risk. The high-capacity vessels will not add to the already known industry streamer count. Seismic industry is a people’s business and I very pleased that we have attracted a tier-one group of people with extensive experience from the seismic industry.” Apparently Petroleum Geo-Services shares Dolphin’s view of the marine seismic future. PGS issued $275 million of equity to help pay for the construction of two fifth-generation Ramform vessels (high density streamers) at a cost of $250 million apiece. Delivery of the first vessel is expected in 1Q 2013, with the second coming to market a year later.



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O F F S H O R E A U T O M AT I O N S O L U T I O N S

Larr y O’Brien • Dedham, Mass.

Procedural automation can improve platform operations Larry O’Brien

Research Director ARC Advisory Group Procedures govern the world of process automation. Process operations such as oil and gas production, hydrocarbon separation, gas processing, and platform utilities, are no exception. While we like to refer to the process industries as being largely “continuous,” in actuality, process operations – including those in upstream production – are constantly in flux. Whether you are doing a startup, shutdown, or are in the middle of a maintenance turnaround, your production platform is governed by procedures and transitional states that can either run smoothly to provide superior operations and safe and orderly start-up/shutdowns, or can cost you in terms of unplanned shutdowns, incidents, lost or delayed production, and lost opportunities.

Enabling human reliability Unplanned downtime is extremely costly. Research shows that the largest reason for unscheduled downtime is operational or human error, which accounts for approximately 42% of the unscheduled shutdowns in the process industries. Of that 42%, some 16% is directly related to procedural error. In our discussions with major operating companies on the future role of process control operators, ARC learned that several majors concluded that this can be addressed through a high-level perspective that enables flawless intervention by exception and relieves operators of manual tasks, freeing time for more value-adding activities. The same research also identified procedure automation as one of the key process automation system functions (along with alarm management and an operational perspective) that can support this environment of flawless intervention, which is so critical offshore. The expertise and operating level of experienced operators can be incorporated into automatic sequences and used to standardize operating methods and to improve the efficiency of all operators. Humans should be allowed to do what they do best and automation should be allowed to do what it does best. Humans are good at ad hoc intervention and non-linear reasoning. They do best when empowered with an overall production cycle perspective. This thinking should be applied to a good procedural automation strategy.

Manual, prompted, or automated Today, operational procedures can be lumped into three primary categories – manual, prompted, and automated.

In manual procedures, the operator performs the necessary actions required, either through personal experience or by following standard operating procedure (SOP) manuals. The consistency with which manual procedures are performed can vary greatly depending upon the level of experience of those carrying out the procedures. Manual procedures also call for manual record keeping, which also can vary in consistency and quality. Electronic records are preferable, but their quality can vary depending upon the accuracy with which the data were entered into the system. There is no way to verify that the manual procedures followed were, in fact, consistent with printed SOPs. Prompted operational procedures go one step further. Here, the procedures are implemented in the process automation system and the operator is prompted to acknowledge that each step has been completed successfully in order to continue. Prompted procedures make it easier to keep electronic records and to verify that operators followed procedures correctly. They also can decrease both transition times and production variability. Like prompted operational procedures, automated procedures are implemented in the process automation system. The difference is that automated procedures will go through the entire operational sequence before stopping, unless either the operator or the system intervenes on an exception basis. Automated procedures can further reduce transition times and variability. Many companies have implemented sequence logic that allows procedures to be automated. However, these have been done largely in an ad hoc framework using custom programming methodologies that can become cumbersome when it comes time to upgrade the automation infrastructure. This ad hoc approach also carries a high cost of ownership, since the end user must maintain the procedures. Changes made to the code over time can create a tangled mass of “spaghetti code” that can be impossible to translate. Many process industry companies today, and particularly global energy companies, are the result of mergers and acquisitions. Along with M&As, come the many system platforms and unstructured code implementations that each participant has accumulated over the years. Clearly, this is not a sustainable way to do business. As a result, more and more owner/operators are standardizing approaches and many have either already adopted, or are considering adopting procedural automation. Major operational incidents are usually the result of a confluence of factors, all converging at the same time to create an environment outside of the normal pre-operations testing environment. Most recent incidents have some sort of procedural element associated with them. Either

proper procedures were not followed, or no standard operating procedure was defined for the operator or maintenance personnel to follow. Many procedures in the process industries tend to be manual or guided procedures. While there is a place for these, any process environment can benefit greatly from a drive to automate many critical procedures, such as startup and shutdown. The need for a procedural automation standard increases as the workforce (including offshore platform crews) continues to lose the highly experienced personnel who understand these procedures. There is no meaningful way to capture that knowledge to guide future operator/maintenance actions properly to prevent incidents. With strong support from the process automation end user community, the ISA 106 standards committee recently was formed to address this issue. Owner/operators within the offshore production industry would do well to investigate and support this initiative.

Offshore oil and gas operations Offshore platforms are as just as susceptible to incidents related to procedures, and perhaps even more so, than other process operations. Here, turnarounds and unplanned shutdowns are the largest sources of lost production. A well-thought-out strategy for procedural automation can help reduce turnaround times, reduce the chance of an unplanned shutdown, and reduce startup times following interlock trips. Startup and shutdown of offshore platforms can be extremely complex compared to the same operations in other process industries, making safety a primary concern. In a technical paper published in 1999, several Petrobras engineers documented a successful expert system for starting up an offshore production platform using procedural automation techniques. Here, procedural automation was implemented to verify auxiliary systems, open the valves on the separation systems, open the subsea wellhead valves, start the oil exportation pumps, and open the choke valves of the wells to begin production, all in the correct sequence, at the correct times, and with minimal human intervention. Documented benefits included standardization of startup procedures to minimize operational missteps and startup times reduced by 30% on average. Readers may be interested to note that this author will host a session on modular procedural automation at the upcoming ARC World Industry Forum in Orlando, Florida, Feb. 7-10, 2011. The forum will also include a session on remote operations management, which should be of particular interest to Offshore readers. For more information, visit www.arcweb.com/res/forumorl.



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Deepwater drilling outlook remains uncertain While some drillers remain positive about the deepwater Gulf, plans are still being stymied by a lack of regulatory clarity

T

he single recurring word heard when industry experts talk about operations in the Gulf of Mexico post-Macondo is “uncertainty.” Of course, offshore drillers and operators are used to uncertainty in the finding and producing of hydrocarbons in deepwater. But now, they are even more concerned with the regulatory and financial uncertainty that stem from new federal rules issued in the wake of the Macondo oil spill. As of now, no one knows what the US government wants, how to achieve those ends, what it will cost, or how long it will take to find out. The deepwater drilling moratorium was lifted in November, but exploratory drilling permits for the Gulf have been few to date. Then, at the end of the year, the Obama administration reversed its earlier decision to allow offshore oil drilling in the eastern Gulf of Mexico and along the Atlantic Coast because of the BP oil spill. In March, Interior Secretary Ken Salazar had announced the expansion of drilling areas, just weeks before the BP accident, as part of a political plan to encourage more domestic oil production in exchange for limits on carbon emissions. The eastern Gulf and the Atlantic seaboard had been off-limits to oil companies for years because of congressional opposition. The recent decision says drilling will remain under a moratorium for those areas for at least the next five years, until stronger safety and environmental standards are in place. Drilling will continue in the central and western Gulf of Mexico, although under a set of new safeguards.

Industry response Following an appearance by DoI Secretary Kan Salazar in Houma, Louisiana, this past November, a group of industry associations sponsored a press conference with the title “End to the Rhetoric.” The sponsors were the Offshore Marine Service Association (OMSA), the Shallow Water Energy Security Coalition, the National Oceans Industries Association (NOIA), the Gulf Economic Survival Team, and the International Association of Drilling Contractors (IADC). “The point we wanted to make is that we are running out of time,” said Jim Adams, interim president and CEO, OMSA. “The

Bruce Beaubouef

Managing Editor Gene Kliewer

Technology Editor, Subsea & Seismic

vessels for safe deepwater drilling and the assets envisioned by the rules are the reasons we need to engage in the discussion. That equipment will be used either here or overseas, and there needs to be a sense of urgency from the government regulators before those assets are gone from the Gulf.” These notes of uncertainty were also sounded at the recent King & Spalding Energy Forum held in Houston. “We are slowly moving in the direction of granting permits,” said Tim Engel, partner, King & Spalding’s Litigation & Antitrust and Energy Practice Groups in Washington, D.C. Engel opened the forum with a presentation entitled “Getting Past the De Facto Moratorium.” However, there remain new rules, interpretive notices, informal advice, etc. There also are environmental hurdles of multiple administrative reviews and what finally comes from environmental litigation.

BOEMRE action plan The plan of action from BOEMRE leading to this point has been to establish the requirements and then develop rules to support the requirement. (The Bureau of Ocean Energy Management, Regulation and Enforcement will eventually be divided into the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement.) Heretofore, the process has been the opposite: First develop the rules and then establish how to meet them. To industry, this “cart-before-the-horse” approach leaves operators with both formal and informal requirements, but no specific methods to attain those requirements. BOEMRE has issued a new interim drilling safety rule and new workplace safety rules, but had only issued notices and informal advisories regarding containment and spill response as of press time. The drilling safety rule sets out BOP equipment/practices and also casing and cementing programs.

Applications for new permits have to have independent expert review of well design and the BOP system. It also has new testing, inspection, and training requirements as well as requiring BOEMRE approval prior to displacing kill-weight drilling fluid. The rules are aimed at tightening workplace safety on offshore rigs and beefing up standards for equipment. Chief executive officers will have to certify that their companies comply with the regulations. Drillers will have to provide third-party verification that blowout preventers are properly designed and can stand up to pressure under all conditions.

New drilling costs Engel estimates that these new regulations, if enacted as written following the comment period, would add an extra $100 million at least to the cost of drilling in the GoM. The federal government also has issued new drilling cost estimates. The new rules will add $183 million a year to the cost of drilling on the outer continental shelf, the Interior Department said in an Oct. 14 notice in the Federal Register. And the rules will add $1.42 million in costs for each new deepwater well that uses a floating rig, the department predicted. Shallowwater wells could cost an extra $90,000. The workplace safety rule makes mandatory a Safety and Environmental Management System (SEMS) and calls for compliance within a year. New rules require a “company official” to certify that the operator will comply with “all applicable regulations” on each deepwater application. There were lessons learned in the Macondo disaster. Some 45,000 personnel and 6,700 vessels were deployed along with 3.8 million feet of containment boom and 9.7 million feet of shoreline boom. There also were improvements in detection and tracking using satellite imaging, thermal/infrared images, and new communications equipment.

Discharge scenarios One area leaving significant doubts for operators is NTL 2010-N06 regarding worstcase discharge scenarios. This is one requirement that has slowed permit issuance as studies are under way to decide how this will be determined. Until an acceptable method of determining worst-case spill volumes is de-



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fined, the site-specific calculations and the assumptions behind them cannot be determined and neither can an Oil Spill Response Plan be revised to meet the worst case. All are required steps to getting a drilling permit. The current direction for determining the worst case is problematic for exploration wells especially. Exploration wells are, by definition, a foray into the unknown. However, the permit application requires determination of the greatest potential daily discharge volume from all producible reservoirs into an open hole. Data also must be provided for well design, reservoir and fluid characteristics, and PVT (pressure volume temperature) characteristics. The informal direction from BOEMRE on this in NTL06 FAQ reads: “You must consider analog drilling or production data, rock and sand strength, formation age, variance in pore pressures, and other relevant geologic and engineering factors to support your determination” of the worst cast discharge. A practical impossibility for an exploration well going into unknown strata. The informal guidance on a Supplemental Oil Spill Response Plan calls for a tiered approach. Once the worst case discharge volume is determined, the operator has to show a response capacity to handle 50% of the discharge within 24 hours; 100% within 36 hours; 200% within 48 hours; and 400% within 60 hours of onset. In determining the response capacity, 30 C.F.R. §254.44 calls for multiplying the manufacturers’ rated capacities by 20% to determine if there is sufficient recover capacity. In short, during permit application review the BOEMRE will be looking for reasons to stop the drilling.

Statutory framework The statutory framework for meeting the environmental demands to drill also are vague. Disregarding the immediate and ultimate affects of environmental litigation on GoM operations, meeting the post-moratorium requirements also remains a moving target. BOEMRE is reviewing the use of categorical exclusions, for instance, and says it will require an environmental assessment for each project. The problem comes because no template for an Environmental Assessment (EA) has been issued. In other words, no determination has been made as to what BOEMRE wants in an EA or what the thresholds for action might be. Among the concerns for operators coming out of the 2010 midterm elections is the call for federal spending cuts. BOEMRE, through DoI, already has requested additional personnel in order to move the operations applications through the system. If the funding is maintained or reduced, BOEMRE says the lack of sufficient staff will retard the pace at which permit applications are processed.

Road ahead In its 2010 Road Ahead for Energy oil and gas conference, Deloitte took a long look at how the events of 2010 might be reflected in 2011. Deloitte also released its 2010 survey of the oil and gas industry. Predictably, the future of the Gulf was at the top of the list of concerns. “Oil and natural gas executives have a tremendous amount of uncertainty about the future of energy in the U.S., including the effects of potential new regulations, the impact of the spill in the Gulf of Mexico, the implications of flat demand, and the long-term role of burgeoning natural gas supplies,” said Gary Adams, vice chairman for Oil & Gas at Deloitte. In introducing the study results, Adams took a special look at the GoM in the post-Macondo era. “Because the Gulf had been so safe, the blowout created shockwaves,” he said. “Regardless of the moratorium lift, it will take six months to meet the new regulations, and this production delay will lead to higher prices and more imports.” Furthermore, permitting delays are expected due to the extended regulatory reviews; which, in effect, leaves the drilling moratorium in place.

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Status of well permits subject to enhanced safety and environmental requirements. Since Oct. 12, 2010, applications for deepwater oil and gas drilling have been accepted for review and approval. Operators must certify compliance with all existing rules and requirements, including those that recently went into effect, and submit information regarding the availability of adequate blowout containment resources.

New risk environment The American Petroleum Institute estimates that a production loss of 80,000 to 130,000 b/d could be felt through the year 2015. The International Energy Agency estimates that 100,000 to 800,000 b/d of new oil supply could be deferred, making domestic demand that much more difficult to meet. Also, because of the new and pending regulations, particularly regarding liabilities, Adams said the deepwater Gulf could become a “niche” play for only the biggest operators. Of the 300 or so companies operating in the GoM, he said only 10 IOCs and NOCs have a market capitalization above the $30 billion liability total reached by Macondo so far. “This new environment for risk means that managers of most companies are betting the entire company on every well,” Adams pointed out. He does not see the Gulf fading in importance, however. “The GoM deepwater is important to the United States as a driver of growth, especially for oil, but for natural gas, too. The GoM provides 30% of the US oil supply and is expected to grow.” “The political risk in the United States is higher (than before), but it is an acceptable risk compared to other operating arenas,” said Branko Terzic, executive director of the Deloitte Center for Energy Solutions. And that should keep the area popular with operators. Another area in which Deloitte expects to see differences is in joint operating agreements and contracts with suppliers. “Those are undergoing revisions now and could result in profound changes (in how business is conducted),” Adams said.

Drilling rule requirements While Salazar said GoM operators should expect “a dynamic regulatory environment” for the foreseeable future, there are a number of new regulations and practices put in place since Macondo. The Ameri-



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can Bureau of Shipping (ABS) notes the following highlights of the new drilling safety rule: • New casing installation requirements • New cementing requirements (incorporating API, RP 65, Part 2, Isolating Potential Flow Zones During Well Construction) • Required independent, third-party verification of blind-shear ram capability • Required independent, third-party verification of subsea BOP stack compatibility • New casing and cementing integrity test requirements • New requirements for subsea secondary BOP intervention • Required functional testing for subsea secondary BOP intervention • Required documentation for BOP inspections and maintenance • Registered Professional Engineer to certify casing and cementing requirements • New requirements for specific well control training to include deepwater operations. The independent, third-party referenced must be a technical classification society; an American Petroleum Institute (API)-licensed manufacturing, inspection, and/or certification firm; or a licensed professional engineering firm capable of providing the verifications required under this part of the rules. ABS provides certification of offshore drilling systems based on its Guide for the Certification of Drilling Systems; the guide incorporates or references the latest industry and international standards. An operator that complies with ABS requirements can obtain the classification notation CDS.

International reaction Reaction to the spill and resulting steps is not confined to the United States. The UK Industry Taskforce on Peak Oil and Energy Security (ITPOES) says the regulatory ramifications are likely to reduce

capacity and increase oil costs within the United Kingdom within the next five years. Seven UK companies – Arup, Buro Happold, Kingfisher, Scottish and Southern Energy, Solarcentury, Stagecoach Group, and Virgin – recently joined to launch a briefing note titled “Peak Oil – Implications of the Gulf of Mexico Oil Spill.” The taskforce report says that owing to the importance of deepwater drilling to the global oil supply, “any future delays or problems associated with deepwater drilling will have much greater impact on supply than is the case today. The impact of the spill is most likely to be felt in project delays due to new legislation, tighter controls, or more inspections of deepwater installations.”

Optimism remains Some positive news came in mid-November, when the International Energy Agency (IEA) announced that drilling requests for the Gulf of Mexico were picking up since the moratorium had been lifted. “Oil companies are queuing up to submit requests to recommence drilling, including many of those previously active in the area,” the IEA said in a report. “Companies remain keen to work in the Gulf of Mexico, seeing it as one of the more profitable regions accessible to them.” Offshore operators remain optimistic about the Gulf. On Oct. 21, Chevron approved a $7.5-billion plan to develop oil and gas fields in the GoM. And Royal Dutch Shell says it expects to produce 220,000 b/d of next year in the Gulf. Apache Corp., a new entrant in the GoM deepwater play, echoed Shell’s optimistic outlook at a recent event in Houston. Carl Scharpf, Gulf Coast Exploration & New Ventures, said the deepwater GoM remains a promising exploration venue. The company marked its entry with the $3.9-billion merger agreement with Mariner Energy announced earlier this year.

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Status of US Gulf of Mexico deepwater discoveries Field name

Location

Aconcagua Alabaster Allegheny Allegheny South Amberjack Anduin Anduin West Angus Arnold Aspen Atlantis Atlas Atlas NW Auger Baha Balboa Baldpate Bass Lite Big Foot Black Widow Blind Faith Boomvang Boris Brutus Brutus Ru Buckskin Bullwinkle Bushwood Caesar Callisto Camden Hills Cardamom Cascade Cheyenne Chinook Claymore Clipper Cognac Conger Constitution Cooper Cottonwood Crested Butte Crosby Cyclops Dalmatian Daniel Boone Danny Dawson Dawson Deep Deimos Devils Island Devils Tower Diamond Diana Diana South Dionysius Double Corona Droshky Dulcimer Durango Einset El Toro Entrada Europa Ewing Bank 1006 Ewing Bank 998 Ewing Bank 878 Falcon Fastball Firebird Friesian Freedom/Gunflint Front Runner Front Runner South Fuji Garden Banks 205 Geauxpher Gemini Genesis Genghis Khan Gladden Glider Goldfinger Gomez Goose Gotcha Great White Green Canyon 235 Green Canyon 29 Green Canyon 39

Mississippi Canyon 305 Mississippi Canyon 441 Green Canyon 254 Green Canyon 298 Mississippi Canyon 109 Mississippi Canyon 755 Mississippi Canyon 754 Green Canyon 113 Ewing Bank 963 Green Canyon 243 Green Canyon 699 Lloyd Ridge 50 Lloyd Ridge 5 Garden Banks 426 Alaminos Canyon 600 East Breaks 597 Garden Banks 260 Atwater Valley 426 Walker Ridge 29 Ewing Bank 966 Mississippi Canyon 696 East Breaks 642 Green Canyon 282 Green Canyon 158 Green Canyon 202 Keathley Canyon 872 Green Canyon 65 Garden Banks 463 Green Canyon 683 Mississippi Canyon 876 Mississippi Canyon 348 Garden Banks 471 Walker Ridge 206 Lloyd Ridge 399 Walker Ridge 469 Atwater Valley 140 Green Canyon 299 Mississippi Canyon 194 Garden Banks 215 Green Canyon 680 Garden Banks 388 Garden Banks 244 Green Canyon 242 Mississippi Canyon 899 Atwater Valley 8 DeSoto 48 Green Canyon 646 Garden Banks 506 Garden Banks 669 Garden Banks 625 Mississippi Canyon 806 Garden Banks 344 Mississippi Canyon 773 Mississippi Canyon 445 East Breaks 945 Alaminos Canyon 65 Viosca Knoll 864 Green Canyon 27 Green Canyon 244 Garden Banks 367 Garden Banks 667 Viosca Knoll 873 Green Canyon 68 Garden Banks 782 Mississippi Canyon 935 Ewing Bank 1006 Ewing Bank 998 Ewing Bank 878 East Breaks 579 Viosca Knoll 1003 Mississippi Canyon 705 Green Canyon 599 Mississippi Canyon 948 Green Canyon 338 Green Canyon 339 Green Canyon 506 Garden Banks 205 Garden Banks 462 Mississippi Canyon 292 Green Canyon 205 Green Canyon 652 Mississippi Canyon 800 Green Canyon 248 Mississippi Canyon 771 Mississippi Canyon 711 Mississippi Canyon 751 Alaminos Canyon 856 Alaminos Canyon 857 Green Canyon 235 Green Canyon 29 Green Canyon 39

Year of discovery

Water depth (ft)

Operator

Status

Onstream

1999 1984 1992 2005 1984 2005 2008 1997 1996 2001 1998 2003 2004 1987 1996 2001 1991 2001 2006 1998 2001 1997 2001 1989 2002 2009 1983 2009 2006 2001 1999 1995 2002 2004 2003 2006 2005 1975 1998 2003 1989 2001 2004 1997 1997 2008 2004 2007 2001 2004 2002 2002 1999 1992 1990 1996 1996 1989 2007 1998 2001 1998 1984 2000 1994 2003 2009 2000 2001 1999 1999 2006 2008 2000 2001 1995 2002 2008 1995 1988 2005 2008 1996 2004 1997 2003 2006 2002 1984 1984 1987

7,039 1,059 3,225 3,280 1,049 2,400 2,696 2,000 1,752 3,063 6,133 9,000 8,810 2,863 7,620 3,373 1,650 6,623 5,000 1,840 6,900 3,539 2,393 2,985 3,160 6,920 1,350 2,700 4,500 7,800 7,213 2,873 8,203 8,987 8,826 3,700 3,452 1,025 1,450 5,100 2,163 2,000 2,846 4,400 3,135 5,876 4,230 2,700 3,000 2,900 3,000 2,300 5,607 2,095 4,670 4,679 1,482 1,312 2,900 1,123 3,150 3,500 1,428 4,642 3,900 1,854 1,000 1,523 3,400 3,000 1,100 3,830 6,100 3,500 3,500 4,250 1,329 2,820 3,488 2,628 4,300 3,116 3,300 5,423 2,972 1,548 7,800 8,009 2,297 1,554 2,300

Total Anadarko Agip ENI BP ATP Newfield Shell Marathon Nexen BP Anadarko Anadarko Shell Shell Mariner Hess Mariner Chevron Mariner Chevron Anadarko BHP Shell Shell Chevron Shell Mariner Anadarko Anadarko Marathon Shell Petrobras Anadarko Petrobras Anadarko ATP Shell Hess Anadarko Newfield Petrobras Nexen Shell BP Murphy W&T Helix (ERT) Anadarko Anadarko Shell Helix (ERT) Dominion Anadarko ExxonMobil ExxonMobil Chevron Murphy Marathon Mariner Anadarko Shell W&T Callon Petroleum Shell Walter Walter Walter Pioneer Newfield Pogo Plains E&P Noble Energy Murphy Murphy Nexen LLOG Mariner Chevron Chevron BHP Billiton Newfield Shell Dominion ATP Statoil Shell Shell Agip Placid Agip

Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Producing Abandoned Producing Producing Producing Development Producing Producing Producing Producing Producing Producing Appraisal Producing Appraisal Development Development Producing Producing Development Producing Development Abandoned Development Producing Producing Producing Decommissioned Producing Abandoned Producing Abandoned Development Producing Producing Producing Producing Producing Development Producing Decommissioned Producing Producing Abandoned Abandoned Producing Abandoned Producing Producing Abandoned Abandoned Producing Producing Development Producing Producing Producing Producing Appraisal Appraisal Producing Producing Abandoned Producing Producing Producing Producing Producing Development Producing Producing Producing Abandoned Development Producing Abandoned Decommissioned Abandoned

2002 1993 1999 2005 1991 2007 2010 1999 1998 2002 2007 2007 2007 1994 1996 2010 1998 2008

Projected onstream

SS SS TLP SS FP SS SS SS SS SS Semi SS SS TLP

2013 2000 2008 2002 2003 2001 2003 1989

SS FP SS TLP SS Semi Spar SS TLP SS FP

2015 2011 2011 2002 1997 2011 2007 2011 2011 1979 2000 2006 1995-1999 2007 2001 2000

SS SS SS TLP FPSO SS SS SS FP SS Spar Semi SS SS

2011 2009 2010 2004 2006 2005 2011 2004 1993-1999 2000 2000 1997 1989 2010 1999 2004 2002 2004

SS SS SS SS SS SS SS Spar SS Spar SS

SS SS SS SS

2000 2005 2011 2001 2003 2009 2001 2012 2014 2004 2005 2000 2005 2009 1999 1999 2007 2011 2004 2005 2006 2011 2010 1984 1988-1990 1998

Prod. type*

SS SS SS SS SS SS SS FPS FPS Spar SS SS SS Spar FPS SS SS SS SS Semi SS Spar Semi



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Status of US Gulf of Mexico deepwater discoveries Field name

Location

Green Canyon 75 Green Canyon 448 Gunnison Habanero Harrier Hawkes Healey Heidelberg Holstein Hoover Horn Mountain Hornet Isabela Jack Jake Jason Jolliet Jubilee Jubilee Extension Julia Kaskida K2 K2 North Keltics King King King Kong King West King’s Peak 1 Knotty Head Kodiak La Femme Ladybug Lena Leo Llano Longhorn Lorien Lost Ark Macaroni Mad Dog Madison Magellan Magnolia Manatee Manta Ray Marco Polo Marlin Mars Marshall Matterhorn McKinley Medusa Medusa North Mensa Merganser Mica/Mickey Mighty Joe Young Mirage Mission Deep Mississippi Canyon 401 Mississippi Canyon 68 Mississippi Canyon 837 Mississippi Canyon 72 Mississippi Canyon 503 Morgus Morpeth/Klamath Mustique Na Kika - Ariel Na Kika - Coulomb Na Kika - E. Anstey Na Kika - Fourier Na Kika - Herschel Na Kika - Kepler Nansen Navajo Navarro Neptune Neptune/Thor Ness Nile Nirvana Noonan North Boomvang1 North Boomvang2 Northwest Navajo Northwestern Ochre Oregano Orion Oyster

Green Canyon 75 Green Canyon 448 Garden Banks 668 Garden Banks 341 East Breaks 759 Mississippi Canyon 509 Green Canyon 82 Green Canyon 589 Green Canyon 644 Alaminos Canyon 25 Mississippi Canyon 126 Green Canyon 379 Mississippi Canyon 562 Walker Ridge 759 Green Canyon 409 Green Canyon 344 Green Canyon 184 Atwater Valley 349 Lloyd Ridge 309 Walker Ridge 627 Keathley Canyon 292 Green Canyon 562 Green Canyon 518 Mississippi Canyon 912 Mississippi Canyon 764 Mississippi Canyon 84 Green Canyon 472 Mississippi Canyon 84 Desoto Canyon 133 Green Canyon 512 Mississippi 771 Mississippi Canyon 427 Garden Banks 409 Mississippi Canyon 281 Mississippi Canyon 547 Garden Banks 386 Mississippi Canyon 502 & 546 Green Canyon 199 East Breaks 421 Garden Banks 602 Green Canyon 826 Alaminos Canyon 24 East Breaks 424 Garden Banks 783 Green Canyon 155 Ewing Bank 1006 Green Canyon 608 Viosca Knoll 915 Mississippi Canyon 807 East Breaks 949 Mississippi Canyon 243 Green Canyon 416 Mississippi Canyon 582 Mississippi Canyon 538 Mississippi Canyon 731 Atwater Valley 37 Mississippi Canyon 211 Green Canyon 737 Mississippi Canyon 941 Green Canyon 955 Mississippi Canyon 401 Mississippi Canyon 68 Mississippi Canyon 837 Mississippi Canyon 72 Mississippi Canyon 503 Mississippi Canyon 942 Ewing Bank 921 Garden Banks 240 Mississippi Canyon 429 Mississippi Canyon 657 Mississippi Canyon 607 Mississippi Canyon 522 Mississippi Canyon 520 Mississippi Canyon 383 East Breaks 602 East Breaks 690 Green Canyon 37 Atwater Valley 575 Viosca Knoll 825 Green Canyon 507 Viosca Knoll 914 Mississippi Canyon 162 Garden Banks 506 East Breaks 599 East Breaks 598 East Breaks 646 Garden Banks 200 Mississippi Canyon 66 Garden Banks 559 Mississippi Canyon 110 East Breaks 917

Year of discovery

Water depth (ft)

Operator

Status

Onstream

1985 2008 2000 1999 2003 2001 2007 2009 1999 1997 1999 2002 2007 2004 2009 2000 1981 2003 2005 2007 2006 2002 2004 2002 1997 1993 1989 2002 1992 2005 2008 2004 1997 1976 1998 1989 2006 2003 2001 1995 1999 1998 2007 1999 1998 1993 2000 1993 1989 1998 1991 1998 1999 2003 1986 2002 1990 2000 1991 2006 2002 2000 2001 2008 2007 1999 1992 1989 1995 1988 1998 1989 1997 1987 1999 2001 1997 1995 1984 2001 1997 1994 2007 2001 2001 2002 1998 2002 1999 1998 1996

2,172 3,266 3,131 2,001 3,609 4,174 2,420 5,000 4,292 4,806 5,400 3,849 6,500 7,000 3,740 2,126 1,750 8,800 8,774 7,087 5,860 3,956 4,000 6,700 2,940 5,386 3,799 5,430 6,541 3,557 5,000 5,800 1,360 1,017 2,487 2,294 2,461 2,179 2,740 3,700 4,400 4,854 2,800 4,700 1,940 1,832 4,300 3,384 2,990 4,376 2,862 2,297 2,125 2,185 5,300 7,900 4,314 4,429 3,914 7,300 1,134 1,353 1,520 2,013 3,099 3,937 1,747 1,000 6,200 7,600 7,000 7,000 6,800 5,800 3,686 4,114 2,024 6,162 1,866 3,950 3,534 3,517 2,700 3,153 3,416 3,937 1,750 1,144 3,400 1,200 1,200

Placid LLOG Anadarko Shell Pioneer ExxonMobil W&T Anadarko BP ExxonMobil BP Hess BP Chevron Helix (ERT) Newfield ConocoPhillips Anadarko Anadarko ExxonMobil BP Agip Anadarko ExxonMobil Shell BP Agip BP BP Nexen BP Stone Energy ATP ExxonMobil Agip Shell ENI Noble Energy Noble Energy Shell BP ExxonMobil Mariner ConocoPhillips Shell Marathon Anadarko BP Shell ExxonMobil Total Nexen Murphy Murphy Shell Anadarko ExxonMobil Mariner ATP Anadarko Apache Walter Walter LLOG LLOG ATP Agip Mariner BP Shell BP BP BP BP Anadarko Anadarko ATP BHP Anadarko Hess BP BP Helix (ERT) Anadarko Anadarko Anadarko Hess Mariner Shell BP Marathon

Decommissioned Development Producing Producing Producing Possible Development Appraisal Producing Producing Producing Development Development Development Development Abandoned Producing Producing Producing Appraisal Appraisal Producing Producing Abandoned Producing Producing Producing Producing Producing Appraisal Appraisal Appraisal Producing Producing Abandoned Producing Producing Producing Producing Producing Producing Producing Appraisal Producing Producing Producing Producing Producing Producing Producing Producing Abandoned Producing Producing Producing Producing Producing Abandoned Producing Appraisal Producing Producing Producing Producing Development Development Producing Abandoned Producing Producing Producing Producing Producing Producing Producing Producing Possible Producing Producing Possible Producing Abandoned Producing Producing Producing Producing Producing Producing Producing Producing Producing

1988-1989

Projected onstream 2011

2003 2003 2004 2013 2011 2013 2004 2000 2002 2011 2011 2013 2011 1989 2007 2007 2013 2014 2005 2006 2002 2000 2002 2002 2003 2002 2013 2013 2012 2001 1984 1998 2004 2009 2006 2002 1999 2005 2002 2011 2004 2002 1999 2004 1999 1996 2001 2003 2000 2002 2005 2000 2007 2001 2000 2010

SS Spar SS SS FPS SS Spar Spar Spar SS SS FPS SS TLP SS SS FPS FPS SS SS SS SS SS SS SS FPS SS SS SS CT SS SS SS SS SS Spar SS SS TLP SS SS TLP TLP TLP SS TLP Spar SS SS SS SS

2011 2005 2001 2003 2009 2011 2011 1998 1996 2004 2004 2004 2004 2004 2004 2002 2002 2012 2008 1997 2013 2001 1999 2010 2007 2007 2003 2000 2003 2001 2000 1998

Prod. type*

MinDOC SS SS SS SS SS SS SS TLP SS SS SS SS SS SS SS Spar SS SS TLP Spar SS SS SS SS SS SS SS SS SS SS SS



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Status of US Gulf of Mexico deepwater discoveries Year of discovery

Water depth (ft)

Operator

Status

Garden Banks 515 Mississippi Canyon 400 Garden Banks 216 Viosca Knoll 830 Viosca Knoll 786 Green Canyon 236 Mississippi Canyon 718 Viosca Knoll 990 Mississippi Canyon 28 Green Canyon 468 Green Canyon 116 Garden Banks 258/302 Ewing Bank 1003 Ewing Bank 958 Mississippi Canyon 765 Viosca Knoll 742 Green Canyon 823 Garden Banks 293 Mississippi Canyon 961 Green Canyon 382 Viosca Knoll 956 East Breaks 713 Mississippi Canyon 248 Mississippi Canyon 292 Garden Banks 877 Mississippi Canyon 204 Mississippi Canyon 252 East Breaks 992 Green Canyon 110 Garden Banks 339 Green Canyon 228 Garden Banks 171 Green Canyon 432 DeSoto Canyon Mississippi Canyon 563 Green Canyon 177 Garden Banks 516 Mississippi Canyon 299 Walker Ridge 52 Green Canyon 141 Green Canyon 654 DeSoto Canyon 269 Alaminos Canyon 815 Mississippi Canyon 849 Lloyd Ridge 001

2001 2001 1996 2003 1995 1998 1995 1985 1986 2006 1985 2006 1999 1994 2000 1997 2004 2009 2005 2002 1985 2003 2006 2007 2001 2006 1999 1996 1987 2008 1985 1989 2009 2004 2009 1999 1996 2000 2009 2008 2002 2003 2004 2002 2005

3,280 1,200 1,450 3,376 1,754 1,969 2,748 1,290 1,864 3,440 2,067 2,310 1,450 1,498 3,650 1,000 4,130 2,100 7,925 3,500 3,214 3,600 3,400 3,400 5,300 3,334 5,200 4,872 1,785 2,240 1,950 1,076 3,400 7,850 6,515 1,320 3,400 5,400 5,750 1,016 4,400 7,509 9,226 3,599 8,340

Marathon Anadarko Hess Chevron Chevron Helix (ERT) Mariner BP BP Hess Shell Anadarko El Paso El Paso Shell Chevron BP Newfield Statoil Murphy Shell Pioneer Noble Energy Noble Energy Anadarko Noble Energy Dominion ExxonMobil Shell Newfield Noble Energy Anadarko Anadarko Dominion Noble Energy Spinnaker Shell Murphy Anadarko LLOG BHP Shell Shell Noble Energy Anadarko

Development Producing Producing Producing Producing Producing Producing Producing Producing Development Producing Producing Producing Producing Producing Producing Appraisal Appraisal Producing Producing Producing Producing Producing Development Producing Development Producing Possible Producing Producing Abandoned Abandoned Appraisal Producing Development Producing Producing Producing Appraisal Producing Producing Appraisal Producing Abandoned Producing

Viosca Knoll 915 DeSoto Canyon 621 Walker Ridge 678 Walker Ridge 508 Atwater Valley 183 Mississippi Canyon 26 East Breaks 430 Viosca Knoll 961 Green Canyon 640 Viosca Knoll 783, 827 Atwater Valley 63 Mississippi Canyon 734 Mississippi Canyon 778 Mississippi Canyon 776 Keathley Canyon 102 Green Canyon 768 Alaminos Canyon 818 Alaminos Canyon 859 East Breaks 623 Mississippi Canyon 561/605 Alaminos Canyon 903 Mississippi Canyon 772 Green Canyon 244 Mississippi Canyon 725 Garden Banks 158 Mississippi Canyon 810 Mississippi Canyon 707 DeSoto Canyon 353 Viosca Knoll 862 Viosca Knoll 823 Mississippi Canyon 984 Atwater Valley 261 East Breaks 689 Green Canyon 726 Green Canyon 490 Garden Banks 605 Mississippi Canyon 506 Green Canyon 516 Mississippi Canyon 496 Mississippi Canyon 354

2003 2003 2003 2005 2003 1994 2000 2001 2002 1984 2000 2004 1999 2000 2009 2004 2004 2004 2003 2008 2002 2002 1994 2003 2001 1991 2004 2007 1995 1997 2009 2002 2002 2007 2009 2009 2005 2001 1997 1977

3,494 8,100 6,900 9,576 3,700 1,100 2,285 4,677 4,017 1,500 4,385 5,724 6,103 5,640 4,132 5,250 9,004 9,627 3,514 6,500 9,687 5,610 2,679 4,300 1,100 3,800 1,538 7,457 1,043 1,137 4,038 8,340 3,905 4,700 3,700 3,400 3,700 4,452 1,800 1,475

BP Anadarko Chevron BP Chevron BP Walter Mariner Chevron Shell ATP Murphy BP BP BP Anadarko Chevron Shell Pioneer Noble Energy Chevron Dominion BP BP Hess Shell LLOG Shell Walter Total Shell BHP Anadarko Anadarko Mariner Newfield Newfield Agip Devon ExxonMobil

Producing Producing Development Appraisal Appraisal Abandoned Producing Producing Producing Producing Development Producing Producing Producing Appraisal Producing Development Producing Producing Development Producing Producing Producing Development Producing Producing Producing Appraisal Producing Producing Appraisal Producing Producing Development Development Appraisal Producing Producing Producing Producing

Field name

Location

Ozona Deep Pardner Penn State Perseus Petronius Phoenix Pluto/BS&T Pompano Pompano II Pony Popeye Power Play Prince Prince Princess Prosperity Puma Pyrenees Q Quatrain Ram/Powell Raptor Raton Raton South Red Hawk Redrock Rigel Rockefeller Rocky Sargent Sable Salsa West Samurai San Jacinto Santa Cruz Sangria Serrano Seventeen Hands Shenandoah Shaft Shenzi Shiloh Silvertip Slam South Dachshund/ Mondo NW Extension South Dorado Spiderman St. Malo Stones Sturgis Supertramp SW Horseshoe Swordfish Tahiti Tahoe/SE Tahoe Telemark Thunder Hawk Thunder Horse Thunder Horse North Tiber Ticonderoga Tiger Tobago Tomahawk Tortuga Trident Triton Troika/Wasatch Tubular Bells Tulane Ursa Valley Forge Vicksburg Viosca Knoll 862 Virgo Vito Vortex West Navajo West Tonga Wide Berth Winter Wrigley Yosemite Zia Zinc

Onstream

Projected onstream 2011

2002 1999 2005 2000 2010 1999 1994 1996 2013 1996 2008 2001 2001 2002 2001 2013 2007 2005 1997 2004 2008 2011 2004 2011 2006 2013 1995 2010

Prod. type* SS SS SS DT CT FPU SS FP SS TLP SS SS TLP SS SS DT FPS SS SS TLP SS SS SS Spar SS SS SS SS SS

2005 2007 2011 2002 2001 2006 2010 2009

SS SS SS SS SS

2010

SS TLP FPS SS

2007

SS

2013

2004 2007 2013 2013 2013 1994 2005 2005 2009 1994 2014 2009 2008 2009 2006 2011 2010 2004 2012 2010 2005 1997 2014 2001 1999 2008 2012 1995 1999 2007 2003 2011 2011 2007 2002 2003 1993

SS SS FPS FPS FPS SS SS Spar SS MinDOC** Semi Semi SS SS SS SS SS SS SS SS SS FPS SS TLP SS FPS SS FP SS SS SS

SS SS SS SS

* CT is compliant tower. FP is fixed platform. FPS is floating production system. FPU is floating production unit. SS is subsea. DT is dry tree. TLP is tension leg platform. ** ATP plans to re-deploy its existing MinDOC to Telemark field after it drains Mirage and Morgus fields. Editor’s Note: First production year and development type are estimated for fields not yet onstream.



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GULF OF MEXICO

Offshore bidding model enhances performance

Bidding results Bid amounts and bid activity have varied dramatically over the last 10 years in the Gulf of Mexico. Figure 1 shows the average bid in dollars per acre for federally-owned lease blocks in the Central Gulf of Mexico over the period 2002 through 2010 for a representative group of operators. These bids include both the winning and losing bids. Chevron, Newfield, Noble, and Woodside

Figure 2. The average overbid per block in total dollars for a representative group of firms and the average for all firms who participated in sales during 2002-2010. The overbid amounts are for the case when two or more firms bid on a single block.

Colorado School of Mines

Average bid ($/acre)

Cushing, OK WTI spot price FOB ($/barrel)

LS213

LS194

LS190

160 LS185

LS182

LS194

LS190

4,000

LS185

LS182

Central GOM, all maps, all water depths

140

Average bid ($acre)

120 3,000

100 80

2,000 60 40

1,000

20 0 2002

0 2004

2006

2008

2010

Year Chevron U.S.A. Inc.

Newfield Exploration Co.

Woodside Energy (USA) Inc.

All

Noble Energy, Inc.

Figure 1. The average bid in dollars per acre for federally-owned lease blocks in the Central Gulf of Mexico over the period 2002 through 2010 for a representative group of operators. Analysis includes four representative firms as well as the average for all firms. Bids include both winning and losing bids. West Texas intermediate oil prices over the same period are shown on the graph.

Average overbid, two or more ($000)

LS213

LS208

LS206

LS205

LS198

LS194

LS190

LS182

LS185

Central GOM, all maps, all water depths 25,000

Average overbid, two or more ($000)

A

nalyses of recent lease sales in the Gulf of Mexico suggest that bid outcomes can be highly uncertain and the associated results for E&P companies who compete in the bid environment are mixed at best. Data indicates significant over-bidding that can materially impact the economics of E&P activities and overall company performance. We observe average overbids that at times exceed $10 million per block and total overbids that exceed $1 billion on a single lease sale basis. Given recent events in the Gulf of Mexico, operators are even more compelled to improve their strategic and operating decisions. Bid-setting decisions can significantly impact the economic viability of being a successful player in this producing basin. Recent developments in bidding models offer companies a more robust alternative for evaluating blocks of interest. The decision models we present can replace bidding behaviors that are often due to incomplete information, poor analysis, or emotions. These models predict the likelihood of competition and the magnitude of competing bids on blocks of interest, as well as recommend the optimal bid amount to maximize firm value. We discuss these econometric and decision analysis models and show how they can better inform decision makers and significantly improve the firm’s performance in the competitive bid environment. The competitive bid model that we discuss has broad implications for firms active in the Gulf of Mexico, as well as firms operating in other international competitive bid environments.

Michael R. Walls, Ph.D. Michael B. Heeley, Ph.D.

20,000

15,000

10,000

5,000

0

2002

2004

2006

2008

2010

Year Chevron U.S.A. Inc.

Newfield Exploration Co.

Woodside Energy (USA) Inc.

All

Noble Energy, Inc.



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GULF OF MEXICO

mum acceptable bid set by the BOEMRE. Even more striking is that in the 2008 Central Gulf lease sale, the total overbid amount for all firms was in excess of $2.3 billion. Recent advances in decision models can go a long way toward improving the quality of bid decisions. The technology provides decision makers with an econometric-based analysis that enables them to better understand previous bidding behaviors in the Gulf of Mexico and their impact on current bidding outcomes. It also offers a forward-looking decision analysis model that recommends an optimal bid amount, given the likelihood of winning at alternative bid amounts, and the operator’s estimated asset value.

Multiple variables

Figure 3. Focal block (blue block) analysis of Walker Ridge 90 lease block in the central Gulf of Mexico includes a summary of the proximal block (yellow blocks) attributes and the statistical results, including the likelihood the block receives a bid and the predicted bid amount.

are all very active in the Gulf of Mexico. The Figure also shows a plot of the spot price of West Texas Intermediate oil over that same period. As expected, bid amounts are highly positively correlated with product prices. Figure 1 also shows the average bid in dollars per acre for All Firms (red line) who participated in the Central Gulf of Mexico lease sales over this period. Note that the Central Gulf lease sales are highlighted on the vertical lines in Figure 1. Across all operators, average bids in 2006 were $256/acre, increased to $977/acre in 2008 and have subsequently decreased to $367/acre in the last Central Gulf of Mexico lease sale in March 2010. In addition, we see significant differences in the average bid per acre for the four operators highlighted in Figure 1. The extent to which operators overbid is of particular interest in this data, since significant overbidding can lead to capital destruction and low rates of return on acquired blocks. “Overbid” can be viewed in a number of different ways. In the case of multiple bids for a single block, the overbid is defined as the difference between the highest (and generally) winning bid and the second highest bid. In the case of a sole bidder for a block, it is the difference between the single bid and the Bureau of Ocean Energy Management, Regulation, and Enforcement’s (BOEMRE) designated minimum bid or Mean Range of Values (MROV). Of course, to win a block an operator’s bid will have some amount of overbid; the challenge is to minimize the overbid amount.

Average overbid Figure 2 shows a plot of the average overbid per block for all firms (red line), as well as Chevron, Newfield, Noble, and Woodside En-

ergy over 2002 to 2010. The overbid amounts represent when there was more than one bidder for a given block. Note that the average competitive overbid in the most recent lease sale was about $2.5 million per block. It has been has high as $8.3 million per block. Moreover, we see from Figure 2 that in our representative group there are overbids that range considerably higher than the average. In fact, we observe overbids as high as $83 million per block in recent lease sales. Another way to characterize these findings is in terms of the “overbid rate.” This metric represents the percentage of overbid as compared to the next closest bid. In the last Central Gulf lease sale, the average overbid rate for cases where there were two or more bidders was more than double the next closest bid. In the case of sole bidders, the average overbid rate was almost six times the mini-

The general purpose of regression models is to learn more about the relationship between several independent or predictor variables and a dependent or criterion variable. Most real world phenomena are multifactorial in nature, meaning more than one factor impacts, or causes changes to the dependent variable. To predict the dependent variable as accurately as possible, it is usually necessary to include multiple independent variables in the model. In our discussion we refer to the lease block of interest as the “focal” block and the nearby blocks as the “proximal” blocks. We use logistic regression to estimate the likelihood that a focal block of interest will receive a bid. In statistics, logistic regression (sometimes called a binary logit model) is used for prediction of the probability of occurrence of an event by fitting data to a logistic curve. In the context of bidding analysis, this form of regression is designed to capture the impact of predictor variables that may influence the likelihood that a focal block of interest receives a bid. For example, the probability that a focal

Table 1. Comparison of predicted values to actual bids for a selected set of lease blocks in the Central Gulf of Mexico Lease Sale 213 held in March of 2010. Map Name

SmartBid Model Block Probability of Predicted Number Receiving a Bid Bid Amount

Winning Bid

Green Canyon Green Canyon Green Canyon Keathley Canyon Keathley Canyon

70 546 800 192 76

98% 97% 93% 96% 98%

$1,596,840 $6,891,131 $445,023 $4,794,854 $6,758,390

$1,389,921 $6,085,555 $381,792 $4,504,900 $7,018,017

Keathley Canyon Keathley Canyon

26 62

89% 96%

$7,400,000 $4,184,023

$9,094,317 $4,277,000

Ship Shoal Atwater Valley Walker Ridge

361 762 594

36% 9% 92%

$550,562 $283,010 $1,024,009

$171,700 $261,450 $880,147

Losing Bid(s) $524,160; $311,040; $224,640 N/A N/A $1,451,520; $823,680 $3,784,320; $1,751,040; $760,320; $673,920; $253,440 $2,557,440 $2,021,760; $1,255,680 $1,100,160; $812,160; $403,200 N/A N/A $253,440



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DISCOVER NEW FRONTIERS IN WEST AFRICA 15TH EDITION CONFERENCE & EXHIBITION 15 - 17 MARCH 2011 INTERNATIONAL CONFERENCE CENTRE ACCRA I GHANA

REGISTER TODAY AND SAVE €200* Offshore West Africa Conference & Exhibition 2011 would like to invite you to attend the premier technical forum focused exclusively on West Africa offshore exploration and production. The 15th annual Offshore West Africa Conference & Exhibition will be held in Accra, Ghana at the International Conference Centre on 15 – 17 March 2011. Offshore West Africa remains the leading source of information on new technology and operating expertise for this booming deepwater and subsea market and is the most significant offshore Africa deepwater technology event in the world, making Offshore West Africa 2011 an event you cannot afford to miss.

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GULF OF MEXICO

block of interest will receive a bid might be predicted from knowledge of the focal block’s attributes such as water depth, offset production, a block that is newly available, estimated MROV, etc. The likelihood the focal block receives a bid may also depend on proximal competitive bidding behavior in prior lease sales, that is, the number of proximal blocks receiving single or multiple bids, the magnitude of bids for proximal blocks, consortium bidding activity, etc. We employ a multiple regression model to estimate the expected bid amount on a focal block of interest. Much like the logistic regression model, we use the proximal block attributes such as water depth, size of the block, estimated MROV, offset production, as well as the competitive bidding behaviors on proximal blocks in prior lease sales to assist in the prediction of the expected bid amount. Multiple regression helps us understand how these measures (the independent variables) relate to the predicted bid amount (dependent variable) on the focal block of interest. In some cases, for example, we find that consortium bidding is more important than multiple bids. One may also detect “outliers,” that is, blocks that should really sell for more, given their location and block attributes. The goal of the multiple linear regression models is to correctly predict the bid value on a focal block of interest using the most parsimonious model.

Proximal blocks Figure 3 shows an example of the focal and proximal block selections for the Walker Ridge 90 lease block in the Central Gulf of Mexico, which was offered for sale in 2009. Note that the proximal blocks may be selected in a number of different ways and the term proximal is relative. For example, proximal blocks may be selected by a geographic distance (i.e., 7 nautical miles) as shown in Figure 3, by a geologic or reservoir trend, or by area of competitive bidding behaviors that is relevant to the focal block of interest. Block attributes and competitive bidding behaviors associated with the selected proximal blocks, and partially shown in the table in Figure 3, are then populated into the regression models to predict the likelihood the block will receive a bid and predict the expected bid amount. In the case of Walker Ridge 90, the statistical models predict a 90% probability that the block will receive a bid and a bid amount of $313/acre ($1.8 million total bid). In fact, this block was won by a consortium of ENI, Cobalt, and Samson at a bid price of $329/acre or $1.9 million. Three other bids were tendered for this block at $182/acre, $89/acre, and $56/acre. Table 1 shows a sample of selected blocks from the most recent Gulf of Mexico lease sale in the central Gulf. The table indicates the block name and number, the statistical predictions of the probability of receiving a bid and the predicted bid amounts, as well as the actual winning and losing bids, where applicable. Using block attributes and prior competitive bidding behaviors from the prior eight lease sales, the predictive power of the regression models are very robust. A significant portion of the variability in bid amounts and likelihood of receiving a bid can be explained by the model parameters. As in the case of any regression model, the predictive capabilities are somewhat limited in certain cases as we are utilizing past bidding behaviors to assist in the prediction of future activity. However, the approach provides powerful decision support in terms of understanding competitive bid behaviors and how it may impact bidding activity on blocks of interest in a competitive bid sale. This bid-setting technology can improve the chance of winning blocks of interest while at the same time reduce the chance and amount of overbidding that can lower the overall economic value of the asset.

Optimal bid The optimal bid analysis (Figure 4) provides a forward-looking approach that considers the likelihood of winning at alternative bid

Figure 4. An analysis of the Walker Ridge 90 block using the optimal bid approach. The Probability of Winning Bid line (green) is derived from the prior winning bid amounts in the Walker Ridge map area of the Gulf. The Total Value line (magenta) represents the value of the asset at alternative bid amounts and the Expected Value line (red) is simply the product of the probability of winning at a selected bid amount and the asset value minus the bid amount.

amounts and the estimated net present value of the block. The peak of the expected value line (red) represents the optimal bid when the firm is attempting to maximize expected value. The peak or turnover point of the expected value line represents the optimal bid when the operator is attempting to maximize the expected monetary value associated with the block. The decisionmaker can also consider the asset value from a probabilistic perspective and view the change in the optimal bid amount as a result of different estimations of asset value. In Figure 4 we can compare the econometric analysis that uses past bidding behaviors and block attributes, with the forward-looking decision analysis approach that estimates the optimal bid amount. In the case of the Walker Ridge 90 analysis, the econometric estimation and decision analysis approach converge to a similar bid amount (approximately $320/acre) and, in fact, an amount that was close to the winning bid.

Conclusions and implications Competitive bidding decisions have strategic and economic importance for E&P companies operating in the Gulf of Mexico, as well as other oil and gas competitive bidding environments across the world. There is significant empirical evidence that firms systematically overbid for lease blocks in amounts that can dramatically impact the economic viability of these assets. Improving the quality of bid decisions can provide a strong foundation and help increase the overall performance of business activities in the Gulf of Mexico and other producing areas that are subject to a competitive bidding environment. The technology described in this paper goes a long way toward improving the quality of bid decisions. Using prior bidding behaviors and lease block attributes, the econometric analysis provides robust estimates of the likelihood of bid activity on blocks of interest, as well as a prediction of the bid amounts. Coupled with a forward-looking decision-analysis model that integrates the bidder’s estimate of the likelihood of winning at alternative bid amounts with the estimated asset value, the technology provides guidance for an optimal bid strategy. Decision support models such as this provide valuable insights with regard to competitive analysis in the bid environment, a more systematic and rational approach to bid-setting, and the ability to improve the chance of winning blocks of interest and reducing the likelihood of significant overbidding.



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D E E P WAT E R H O R I Z O N A F T E R M AT H

Drilling permits being reviewed, says Bromwich Return to normality hinges on BOEMRE’s proposed budget hike and future reforms

P

rogress in returning Gulf of Mexico deepwater drilling and production activity to something like pre-Macondo levels is getting nowhere…slowly. Not only that, despite the industry’s efforts to meet the demands made by units of the Executive branch – chiefly the Interior Dept. and its offshore deputy, BOEMRE – it appears as though producers and their contractor/subcontractors face a much longer wait to get back to work than anticipated, even though the much-maligned moratorium on drilling in both the deepwater (and shallow-water) Gulf was “lifted” more than two months ago. As to the limbo-like nature of the outlook for Gulf deepwater drilling and its lack of well permitting that some now are calling a “permit-orium,” the industry appears to be doing its best to comply with a more stringent BOEMRE-ordered safety and environmental regime and new equipment inspection and accountability rules. But the facts speak for themselves: • Admittedly, according to Director Michael R. Bromwich, BOEMRE has been severely understaffed and under-funded, and is competing with the industry itself in hiring competent geophysicists, geologists, engineers, and inspectors, without whom the bureau’s handling of already severely curtailed permitting could be delayed even more. • A presidential panel is pledged to recommend steps that will constitute a “major transformation” of the offshore industry’s approach to both personal and environmental safety that involves both equipment and personnel. These and other such recommendations are scheduled to be handed to President Obama on Jan. 12, 2011. • A joint investigation by the Interior and Homeland Security departments, though still ongoing, is scheduled to identify the guilty parties involved in causing the fatal Macondo explosion and the subsequent major oil spill. Its findings – and perhaps even recommendations for Justice Dept. civil or even criminal indictments – are due to be handed down in late March 2011. • A new Republican-dominated House of

Representatives is bent on cutting new federal spending, beginning when the 112th Congress convenes in January 2011. This could leave the probability of a significant increase by Congress of Interior’s (and therefore BOEMRE’s) annual budget in some doubt. • The Obama administration has rescinded its earlier decision to expand offshore exploration into the eastern Gulf and along the Atlantic coast, citing shortfalls in federal regulation. This extends that Presidential moratorium for at least the next seven years. • Drilling company management – who have remained patient through the all-Gulf moratorium, keeping most of their deepwater rigs in place – may soon be forced to move them to other parts of the world where more timely and regular work is available. These conditions alone could lend a decidedly negative tang to the future of Western and Central Gulf deepwater exploratory and development drilling for months to come.

Reforms call for people, money This past May, BOEMRE (Bureau of Ocean Management Regulation and Enforcement) was quickly organized under Executive Order to succeed the former Minerals Management Service (MMS) as the federal body charged with oversight of leasing, revenue collection, and drilling and production regulation in federally controlled waters. The revamp was necessitated by what President Obama deemed a “too cozy” relationship among MMS regulators and the offshore industry. As expected, however, as with any “new” governmental organization, BOEMRE and its sub-agencies suffer from expansion bottlenecks in performing their various mandates. Interior Secretary Ken Salazar has asked Congress to help enlarge the BOEMRE’s professional staff and acquire updated equipment with a $100-million budget increase for fiscal 2011. However, the probability of actual receipt of such funding is somewhat moot currently, given the desire for a spending cap among the Republican majority in the House, where all appropriations bills originate.

F. Jay Schempf

Contributing Editor

BOEMRE Director Michael R. Bromwich says agency’s work “is far from complete.”

It doesn’t help either that even other Interior Dept. offices have looked askance at BOEMRE’s stated goal of becoming a more thorough regulator of petroleum industry operations in federal waters. An 88-page report, ordered by Salazar in May and delivered earlier this month by Interior’s acting Inspector General Mary Kendall, lists a number of “regulatory, organizational, and managerial weaknesses” inherited by BOEMRE from MMS, including the agency’s having too few inspectors to perform oversight of the offshore industry, particularly for the thousands of production facilities currently in the Gulf. What’s more, the report charged that BOEMRE’s manpower, particularly in the Gulf region, is inadequate for handling what could be a major increase in post-moratorium applications by the industry for drilling permits in the next few months. The high-intensity work load associated with an eventual major influx of permit applications, along with pressure coming from operators for shortened review periods, the report continues, could result in more delays in processing times – and even employee burnout – from efforts to meet such increasing demands. Obviously taken aback by the finger pointing from his own ranks, director Bromwich quickly issued a response letter to Salazar, calling the Kendall report “dated and incomplete,” and failing to take BOEMRE’s ongoing reforms and improvements (increased hiring in anticipation of the requested $100 million Interior Dept. budget appropriation) into account. Not surprisingly, offshore operators are largely in favor of Congress allocating more funds for BOEMRE, et al., as well, since that could hasten environmental reviews, drilling permits, and inspection of Gulf deepwater drilling and production activities. But the industry’s concern also lies in the prospect that when the reports come down from the various Macondo-based investigations during the next couple of months, some or all



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WHERE IT ALL

Conference & Exhibition February 1-3, 2011 Moody Gardens • Galveston, TX www.topsidesevent.com Join Offshore magazine in the launch of TOPSIDES, PLATFORMS & HULLS Conference and Exhibition, the industry’s newest event covering the design, engineering, construction, transportation, installation and modification of topside structures, platforms and hulls. Focusing exclusively on this dynamic market, TOPSIDES, PLATFORMS & HULLS provides a strategic platform for networking, information exchange and new business development. To book exhibit space, contact: Sue Neighbors

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D E E P WAT E R H O R I Z O N A F T E R M AT H

Oil capture/containment systems to abound in GoM region

of the recommended reforms could be sanctioned by Executive Order from the President, without benefit of direct congressional involvement.

The US Gulf of Mexico offshore industry staging area soon may be well-stocked with rapid-response oil spill capture and containment equipment that, if combined, could capture and/or burn as much as 200,000 b/d of crude oil and liquids escaping from compromised wells drilled in up to 10,000 ft of water. In early December, Helix Energy Solutions Group Inc., Houston, announced it was putting the final touches on a deepwater containment system – as yet unnamed – using its own deepwater production and construction vessels, two of which played key roles in the Macondo oil spill response, along with subsea and surface equipment that Helix considered most useful in that effort. The Helix system, to be offered commercially to Gulf operators, could be used exclusively or to supplement that of the Marine Well Containment Co. Inc. (MWCC), the $1-billion non-profit system announced in July by ExxonMobil, Chevron, ConocoPhillips, and Shell. Helix says their system is available immediately, while MWCC says their complete system will be ready to go in about 12 months. The MWCC system is being financed by its four founders, along with BP Americas, which donated its own equipment used in capturing Macondo oil. MWCC is asking other Gulf operators to participate in the organization in various ways. The Helix operation will be offered to all operators – including both large and smaller independent producers – under a retainer-like structure. The company says it is lining up companies to enlist in the system, but would not name any while negotiations continue. The Helix capture/containment system is based on a subsea shutoff device (SSOD) placed atop sea-floor BOP or production equipment. Combining the SSOD with an Intervention Riser System (IRS) then allows well flow to be channeled to production and storage vessels at the surface. Installation of the SSOD and IRS would be handled by the company’s Q4000 DP-3 multipurpose floating intervention/ production platform, along with its Express deepwater construction ship, with produced fluids separated and stored aboard the Helix Producer 1 DP-2 floating production vessel, supplemented by FPSO vessels serving shuttle tankers or production facilities tied into pipelines to shore. All three Helix vessels played key roles in the Macondo spill response. Helix says its vessels and equipment array can handle up to 55,000 b/d of oil, 70,000 b/d of liquids and 95 MMcf/d of natural gas in water depths to 8,000 ft. Natural gas production would be separated and then flared. The company did not place a monetary value of its system.

Bromwich clears the air

System similarities With Technip as its chosen front-end engineering and design contractor, Marine Well Containment plans to deploy a newly designed and fabricated hydraulic/electrical-controlled subsea containment assembly onto a compromised well for a permanent connection and seal equipped with a suite of valve adaptors and connectors to interact with BOP, wellhead, lower marine riser package, and casing string interfaces. Oil would be captured by the containment assembly and flow through a manifold and then into flexible pipe to one or more free-standing flexible risers configured to connect with capture/ storage vessels. All production equipment will be fitted with hydrate inhibition systems. At the surface, the MWCC system’s capture vessels will be either FPSO-type ships or conventional tankers equipped with modular process equipment. Either would offload into shuttle tankers or connect to pipeline transportation platforms. All containment vessels will be equipped to quick-disconnect from riser assemblies and umbilicals in case of weather interference with operations.

In any case, the sharp end of Interior’s goal to bring “the most aggressive and comprehensive reform of offshore oil and gas regulation and oversight in U.S. history” is BOEMRE and its director, Bromwich. While the agency already has launched a number of emergency regulatory changes in response to lessons learned from the Macondo spill, Bromwich has left little doubt that more reforms are planned. Meanwhile, as keynote speaker at a Dec. 8 offshore oil and gas law conference in New Orleans, Bromwich addressed the significant slowdown in the granting of deepwater drilling permits by BOEMRE, which some industry officials and even lawmakers have called a “de facto” moratorium. Not so, says he, noting that the industry’s post-Macondo success in compliance with new rules in the areas of drilling safety, subsea containment, and spill response was central to Interior Secretary Salazar’s lifting of the moratorium in October, two months early. He mentioned the industry’s development of a number of containment mechanisms intended specifically for deepwater, including the launching in July of the Marine Well Containment Corp. by four major companies and subsequently joined by BP, operator of the Macondo well. He also noted the recent announcement by Helix Energy Solutions Group Inc. of a commercial rapid response containment system (available via a retainer-like financial structure) also to be installed in the Gulf area (see accompanying story). Since the moratorium was lifted, said Bromwich, BOEMRE has worked diligently to review applications for deepwater permits and ensure that they comply with the new regulations. However, he added, the agency still faces a severe shortage of resources, but has temporarily re-assigned personnel from other regions to help in permit reviews. “We are not slow-walking them in any way or for any reason,” said Bromwich, who then added: “I want to be clear. We will not cut corners in the permit review process and permits will be approved only when we are satisfied that all applicable regulatory requirements are met.” Referring to the new regulations, Notices to Lessees (NTLs) and how his agency will apply National Environmental Protection Act (NEPA) requirements for deepwater drilling, Bromwich said BOEMRE is preparing a “guidance document” intended to describe the way forward. This document, he said, will resolve many of the questions being posed by operators. He did not say when this document will be made available, however.

No big rule changes ahead As for additional reforms, Bromwich said BOEMRE’s work “is far from complete,” and added that in the near future, the agency will implement further safety measures. These will include establishing additional requirements for BOPs and ROVs. The agency will also consider additional workplace safety reforms, including requirements for independent third-party verification of operators’ Standard Emergency Management Systems (SEMS) programs. But he also noted that the anxiety currently being expressed by companies, trade associations, and members of Congress over whether BOEMRE will soon change the drilling permitting rules significantly should be allayed. “This is not the case,” he said. “Barring significant, unanticipated revelations from the ongoing investigations into the root causes of the Deepwater Horizon incident, I do not anticipate any further emergency rulemakings.” At the same time, he said, BOEMRE will continue to analyze information that becomes available, including the findings and recommendations of the various ongoing investigations into what caused the Macondo spill, and “will implement reforms necessary to make offshore oil and gas production safer, smarter and with stronger protections for workers and the environment.”



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LAGCOE 2011

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GEOLOGY & GEOPHYSICS

Using seismic-while-drilling technology to reduce uncertainty

T

he sedimentary basins of the Gulf of Mexico (GoM) exhibit a wide range of different geological characteristics, especially in the presence of complex salt bodies. Surface seismic surveys do not accurately image the borders and bases of salt domes. In addition, rapid lateral and vertical changes in acoustic velocity introduce uncertainties into the estimation of depth from seismic data. In exploration areas, the lack of a priori information means that several uncertainties cannot be eliminated until at least one well has been drilled that provides reliable downhole information that can be integrated with the seismic data to calibrate depth models.

Well planning The Well-1 was drilled through the flanks of, and then beneath, a salt dome in a deepwater area of the southeast region of the GoM. Analysis of a 3D seismic dataset indicated shallow drilling hazards in the area, which constrained the options for the well location at the surface. Other drilling challenges included

Alfonso Mora Rios Aciel Olivares Leonardo Aguilera Rito Gaitan

PEMEX Adrian Cristian Sanchez Rodriguez

Schlumberger the possible presence of a salt tongue at about 1,800 m (5,905 ft) related to the main salt body, and stresses related to salt tectonics. A geomechanical study was performed to determine how stresses could affect wellbore stability in the section close to the salt flank. A rapid increase in pore pressure was suspected to exist in sediments beneath a fault plane at 2,200 m (7,217), so it was considered important to set the 16-in. casing just below the fault. PEMEX decided to use the seismicVISION seismic-while-drilling service to deliver real-time check-shot and interval velocity measurements, plus data for look-ahead vertical seismic profile (VSP) processing.

Seismic-while-drilling Seismic-while-drilling technology provides borehole seismic data while the well is being drilled – without disrupting operations. The seismic source is an airgun array deployed a few meters below

Principles of seismic-while-drilling.

the water. The data are recorded using three geophones oriented orthogonally in x, y, and z directions, plus two hydrophone pressure sensors usually transmitted to surface through mud-pulse telemetry. The measurements enable accurate time-todepth conversion of surface seismic data and provide critical indications of the structures of reflecting horizons ahead of the drill bit to support drilling and well construction decisions such as casing points and target interception. Real-time velocity measurements also can be used to update pore-pressure predictions from the surface seismic, helping to avoid drilling hazards.

Feasibility study A study was performed to determine if the seismic-while-drilling technology could help with the drilling challenges of Well-1 and, if so, to design optimum data acquisition parameters. The study was based on a 3D model with interpreted horizons and velocities from the surface seismic – including for the main salt body – plus density values and the proposed well trajectory. The study focused on two key objectives: detecting salt ahead of the drill bit in the shallow (16-in.) section and measuring proximity to the main salt body in the deeper (13 3/8-in.) section. Two scenarios were modeled for the shallow section – one with clastic sediments and the other including a salt tongue associated to the salt dome. This latter scenario could pres-

Surface seismic section showing the match with the real-time VSP and the drillbit position. On the VSP, the data below the drill bit show homogenous reflections and not the strong amplitude expected for salt presence.



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(Left) Salt proximity results (red dots) vs. interpretation. (Upper center) Salt flank from interpretation vs. salt proximity. (Lower center) Interpreted salt was moved to adjust with salt proximity results. (Right) Table showing the distances between salt flank and well position for each recorded station.

ent risks, as it would normally require changes in mud weight and also could require additional casing at the salt exit. The simulations assumed sensors along the whole 16-in. vertical section (1,500 – 2,200 m [4,921 – 5,905 ft]) and a zero offset VSP (i.e. having the energy source at the rig location). The study showed that seismic-while-drilling data could differentiate between the two possible geological scenarios. This difference will lead to higher amplitude reflections from salt/sediment interfaces than those between sediment layers. Modeling of the deeper (13 3/8-in.) vertical section focused on optimizing the measurement of the distance between the well and the flank of the main salt body. A key objective was to determine the best location for the seismic source at the surface to deliver most energy to seismic-while-drilling sensors below the salt, taking into account ray bending caused by the complex geology. The study determined that the optimal location for the source was 2,700 m (8,858 ft) from the rig at an azimuth of 270°.

Acquiring VSP data The BHA included a seismic logging-whiledrilling (LWD) tool located 33 m (108 ft) from the drill bit. The source array of 1,200-cu-in. capacity was deployed from a service vessel. The (nominally) zero offset VSP data for the 16-in. section were acquired with the vessel stationed near the rig to avoid potential interference with drilling operations. Seismic measurements were acquired at 17 levels between 1,503 and 1955 m (4,931 and 6,414 ft). The data were acquired in real time and transmitted on-site for quality control (QC) and additional processing. For each level, time-to-depth relationships based on check-shots were provided to the drilling and operations team members who used the information to update the drill bit position within the 3D seismic volume. After processing of the first five levels, a VSP corridor stack was prepared that provided information ahead of the

drill bit. The VSP was updated constantly as new levels were acquired and integrated into the surface seismic data at the well location to check and confirm the drill bit position. Analysis of amplitudes in the processed VSP data indicated the presence of clastic sediments rather than a salt tongue ahead of the bit, validating the initial interpretation of the geology and increasing confidence in drilling decisions. Drilling of the sandstone and shale interval between 1,800 m and 2,000 m (5,905 and 6,561 ft) subsequently confirmed the interpretation of the VSP results provided the seismic-while-drilling data. The next challenge was to set the 16-in. casing at the correct position – just below the fault plane. The real-time check-shot data enabled the drill bit position to be mapped accurately within the seismic volume, and from measured velocities it was possible to estimate the distance from the current drill bit position to the fault plane. The start of the fault zone was estimated to be at 2,080 m (6,824 ft), and the sequence of upward-dipping sediments – suspected to have higher pore pressure – was predicted to start at 2,140 m (7,021 ft). Based on this information, when the bit reached 2,140 m, drilling was stopped and the 16-in. casing set to avoid any potential drilling problems in the event that abnormal pressures would be encountered below the fault.

Measuring salt proximity A total of 18 levels were recorded between 2,175 and 2,658 m (7,136 and 8,720 ft). The seismic-while-drilling information was used by the processing team to estimate the distance between the well trajectory and the salt flank. Inversion of the seismic data to derive this distance was constrained by the 3D velocity model, updated with new information as it became available. Water velocity was assumed to be 1,500 m/s and salt velocity 4,500 m/s, based on previous measurements of salt bodies. Seismic velocity in sediments

above the salt dome was determined from the check-shot survey acquired by the seismicwhile-drilling tool in the previous section. A real-time salt proximity solution was computed at every level. Estimations of the current horizontal distance between the seismicwhile-drilling receivers and the salt flank were delivered to the G&G and drilling team every few hours. This distance was expected to be a minimum of 200 m (656 ft), but inversion of the real-time measurements indicated that the well was closer to the salt dome than expected. At its minimum, the horizontal distance was 163 m (534 ft) at 2,573 m (8,441 ft) depth; however, it was not considered necessary to change the well trajectory unless the distance was to fall below 150 m (492 ft), which it did not. Seismic-while-drilling processing and interpretation support was provided continuously, 24/7, to the drilling operations team until the well reached 2,658 m (8,720 ft), at which depth it was determined that the critical zones had been drilled and the trajectory was moving away from salt dome, so it was no longer necessary to make the measurements. Information acquired during drilling confirmed that the prestack depth migration (PSDM) results obtained from the 3D surface seismic dataset provided an accurate depth image of the salt dome. Interval velocities measured while drilling were used by the geomechanics team to recalibrate its models, especially for pore pressure prediction, bringing additional value to the information recorded.

Conclusions Seismic-while-drilling technology helped to reduce drilling uncertainty in an area of complex geology related to the presence of salt bodies. Real-time VSP imaging provided information ahead of the drill bit that confirmed the well trajectory would pass through a clastic sediment sequence rather than a salt tongue as was considered possible by interpreters of the surface seismic data. Real-time check-shot information made it possible to position the drill bit on the seismic section with great accuracy, reducing uncertainty related to depth conversion. This information also made it possible to optimize the position of the 16-in. casing to avoid potential problems related to increased pore pressure below a fault. Seismic-while-drilling data provided a real-time estimation of the distance between the well trajectory and the flank of a major salt body, providing confidence to keep the well within the planned minimum proximity to the salt. The seismic-while-drilling results confirmed the accuracy of a model developed for the salt dome based on PSDM of 3D surface seismic data. Seismic velocities measured while drilling were used to recalibrate subsurface models, reducing uncertainty in pore pressure prediction.



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RISK MITIGATION CONSEQUENCE MITIGATION

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Using gravity gradiometry to explore subsalt Whether applied to licensing, frontier exploration, mature plays, prospect generation, or evaluation, gravity gradiometry imaging is a powerful de-risking and exploration tool Neil Dyer

ARKeX

W

ith offshore Brazil, the Gulf of Mexico, and offshore Africa all containing significant subsalt discoveries and many of them featuring complex overburdens, seismic technologies are under pressure to deliver firm target locations for drilling and often over large areas. In Brazil, for example, the current exploration focus on offshore subsalt plays in the Santos, Campos, and Espirito basins extends over 800 km (497 mi). While recent seismic technology advances such as enhanced-azimuth acquisition and 3D pre-stack depth migration have improved subsalt seismic interpretation, a clear subsalt image and the creation of a robust earth model around salt bodies still remains difficult to achieve. Too often the seismic wavefield is distorted and illumination irregular, leading to incomplete ray distribution for seismic migration and a sub-optimal velocity model. With deepwater drilling costing as much as $100 million per well and operators demanding high quality imaging from their subsalt prospects, it has become more important to draw upon other sources of geophysical data. One such example is gravity gradiometry imaging (GGI).

Geology (A), GGI (B), seismic (C) and borehole (D) data integrated into a comprehensive structure and material property model fitting all observations. (C) courtesy of ION.

Gravity gradiometry and subsalt GGI maps small density variations in underlying rocks by measuring the gradient of the Earth’s gravity field, providing a broad band measure of the Earth’s gravitational field. The relatively low density of salt in comparison with typical host material and the typical morphology of salt bodies (both being the principal causes of problems with seismic imaging) tend to represent ideal targets for detection and modeling using high-resolution gravity gradiometry. With the operator requiring as many data sets as possible to reduce risk on presalt targets, the integration of GGI to the asset knowledge base aids the accurate mapping of the density interface between salt and the surrounding rock, and adds 3D structural and velocity constraint to otherwise interpolated fields. Furthermore, the independent verification and improved interpretation risks offered through the tight integration of GGI with seismic data can avoid redundant migration iterations and deliver increased confidence in field appraisals. GGI comes with increased measurement accuracy and bandwidth and careful construction of a rock-physics template linking the modeled density (from GGI) to the seismic velocity. Cooperative interpretation of all input measurements yields a comprehensive Earth Model. This represents the collation of borehole, surface, seismic and gravity gradiometry information integrated into one consistent interpretation. To illustrate the benefits of airborne gravity gradiometry data over conventional gravity data, compare both data types over a salt structure. The accompanying example demonstrates the superior

Comparison of airborne gravity gradiometry (on left) and conventional gravity (on right) data sets over a salt structure. Courtesy of Maurel et Prom.

measurement of the gravitational field that a gradiometry survey provides (left), resulting in both improved spatial resolution and definition of geological features. This further demonstrates the value of GGI when combined with incomplete seismic data. The illustration shows how a well constrained salt map has been developed in an area where seismic data is sparse and of poor quality. The precision of the GGI-derived model, along with access to pre-stack seismic data, led to an accurate velocity/density arrangement, improved correspondence between the seismic and GGI interpretations, and the development of the salt surface shown in blue.



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How GGI has helped develop a well constrained salt map in an area where seismic data is sparse and of poor quality. The precision of the GGIderived model, along with access to pre-stack seismic data, has led to the establishment of an accurate velocity/density arrangement. The development of the salt surface is shown in blue. Courtesy of Maurel et Prom.

GGI is not limited to shallow targets – a common misconception. GGI is able to measure longer wavelength information beyond 20 km (12.5 mi) sufficiently to resolve deep geology. This is important particularly in the case of salt where GGI data has been used to resolve base salts in the deepwater Gulf of Mexico, as the following case study demonstrates.

Resolving the K-2 salt structure The K-2 field is in Green Canyon block 562 in the deepwater Gulf of Mexico, 180 mi (290 km) south of New Orleans. The field includes a massive salt body with thickness in excess of 10,000 ft (3,048 m). GGI helped recover the salt structure so it could be imaged successfully by the migration algorithm. Previously, pre-stack depth migration had a vital role in exploring K-2, providing an excellent definition of the salt body where the salt has a tabular morphology. The flank of the K-2 salt, however, proved more difficult to illuminate with the steep face (around 60º) and the unique shape, leading seismic shadow in the region of interest. With the location of the base of salt having a significant impact on the estimation of field size, it was critical to determine its position so that the field could be appraised properly. GGI was used at K-2 as an independent source of information which, upon inversion, provided a clearer picture of the flank of the K-2 salt and demonstrated that its base has a keel structure. In gravity gradient inversion, the initial 3D earth model is constructed from the available support data and seismic interpretation, and the gravity gradient field computed for the model. In the case of K-2, the earth model was constructed using the Kirchoff pre-stack depth migrated (PSDM) volume, with density values assigned throughout. In the sedimentary formations overlying the salt and on the flanks of the salt, for example, the density distribution was defined by appropriate scaling of the PSDM velocity field. In the subsalt section, the model was defined using seismic horizons interpreted on the PSDM volume with a constant density value assigned to the layers between a pair of interpreted horizons. The final comprehensive Earth Model honored the seismic data, GGI data, and other geologic information. GGI inversion succeeded to delineate the base of salt in the area which had not been imaged with seismic data, and shows that the salt base is not tabular but possesses a shallow keel. The keel is approximately 4,000 ft (1,219 m) in depth, has a symmetric profile, and is oriented in a northwest/southeast direction. This example demonstrates the value in using data from as many

Contrast between the excellent image obtained under the tabular salt compared to the lack of any image underlying the peak of the salt structure in the K-2 field. Courtesy of Anadarko.

different sources and technologies as possible to define a salt structure. In this way, results can be cross-validated, and the operator can image structures economically and quickly, resolve geological uncertainties, and develop a more complete picture of the subsurface. As seismic imaging companies gain familiarity with the enhanced resolution and bandwidth of GGI, workflows are developing to integrate effectively and efficiently GGI datasets into seismic velocity modeling campaigns.

Beyond data processing There is another strand to the use of GGI as an exploration tool – not simply as a means of enhancing existing seismic data (as in the case of the K-2 structure), but also to help shape, design, and optimize new surveys to improve the seismic images. In the K-2 case, GGI was integrated with 3D seismic data. In both cases, if it is necessary to acquire additional seismic data to de-risk a drilling decision, the 3D GGI derived structure can be input to illumination modeling to design the most efficient acquisition scheme. For example, the last few years have seen an embracing of new seismic acquisition technologies, such as multi-azimuth (MAZ), wide-azimuth (WAZ), and rich-azimuth (RAZ), to address the illumination problems of previous, narrow azimuth seismic surveys. Despite the huge volumes of data they acquire, such surveys, however, come at considerable expense with WAZ surveys requiring as many as four vessels and being up to four times as expensive as a narrow azimuth survey. Here, GGI potentially can provide an economically efficient and better targeted solution where a GGI survey can optimize the design and acquisition of a second seismic survey and optimize the original Earth Model. In this way, GGI is not just filling in the details from an original seismic survey at the post acquisition stage, but is playing a fundamental role in directing the survey design toward the most efficient solution to the illumination problem at hand. Whether applied to licensing, frontier exploration, mature plays, prospect generation, or evaluation, GGI is a powerful de-risking tool and a driving force in exploration in salt provinces today. The next few years are likely to see GGI taking up an even more prominent role.

Acknowledgements Potential field measurements by their nature require collaborative interpretation. ARKeX thanks its clients and colleagues for their input into development of these concepts from ideas to commercially viable products. www.offshore-mag.com • January 2011 Offshore 61


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DRILLING & COMPLETION

Analysis confirms effectiveness of gilsonite as offshore shale stabilizer HSE advantages, cost savings also make contribution Bill Britton

American Gilsonite Co.

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n independent evaluation has verified the effectiveness of gilsonite as an HSE acceptable and high-performance inhibition and fluid loss control additive for water-based fluids used to drill highly reactive shales. The laboratory analysis of four water-based muds (WBM) compared two blends of treated gilsonite with sulfonated asphalt, which is a widely used shale stabilization and fluid loss control agent. In the series of tests, lignite/lignosulfonate, KCl, PHPA, and lime-based drilling fluids were examined on a triaxial tester that specifically evaluates the influence of drilling fluids on shale stability under simulated downhole conditions of stress and fluid flow. Depending on the WBM analyzed, the sample muds treated with naturally occurring gilsonite exhibited either marked improvement or equal performance with respect to shale stabilization and fluid-loss control. Over the years, the development of a WBM that approaches the shale inhibition and other high-performance characteristics of oil and synthetic-based muds has been the long-sought “holy grail” of the drilling fluid industry. While invert emulsions typically are the systems of choice for technically challenging applications, particularly when the targeted formations contain highly reactive shales, their comparatively high unit costs, ever-tightening environmental regulations, logistical issues, and other limitations have spurred the industry to seek alternative aqueous fluid systems.

Advantages in deepwater The engineering of a high-performance water-base drilling fluid capable of inhibiting reactive shales to maintain wellbore stability is particularly advantageous for young sedimentary basins and in downhole environments featuring narrow fracture and pore pressure gradients, such as are found often in deepwater. While strides have been made to develop high-performance aque-

ous systems, R&D efforts continue to focus on cost-effective and environmentally acceptable additives that are proficient in inhibiting water-sensitive shales, thereby preventing the bit balling, accretion, wellbore instability, and low rates of penetration (ROP) resulting from poor shale stabilization. The latest test results verified the capability of gilsonite as an effective and competitive option to both control fluid loss and inhibit reactive shales. Gilsonite is a naturally occurring glossy black asphaltic, solid hydrocarbon resin with a low specific gravity. Various industries have used the material for years as an additive in carbon black dispersing agents, hard resin printing inks for newspapers and magazines, asphalt modifying agent for road paving, and as an additive in sand molds used by the foundry industry. For more than 60 years, it also has been used in the E&P industry as a versatile additive for cementing slurries and drilling fluids, including use as a fluid loss additive in oil- and synthetic- based drilling fluids. In some cases, blended gilsonite additives have been documented as saving as much as $1 million per well by resolving differential sticking and consequences of borehole instability, while also reducing torque and delivering exceptional lubricity in deviated wells. Further, gilsonite is non-carcinogenic, thereby delivering HSE advantages compared to sulfonated asphalt and some other shale stabilization blends. Filtrate invasion is problematic in water-based drilling fluids in that it can destabilize shales and cause myriad drilling problems, including borehole enlargement, stuck pipe, sloughing shale, and excess bridging during trips. Specially treated gilsonite grades has proven effective to eliminate or reduce filtrate invasion in aqueous drilling fluids in both offshore and onshore applications.

Testing protocol Historically, owing to the mechanism in which gilsonites and asphalts protect formations, assessing the precise shale stabilization capacity of these materials has been difficult using standard laboratory bench tests. Both of these additives physically shield water-

Comparison of the reduction in erosion and swelling on cores of KCl, lignite, and PHPA water-based drilling fluids tested at 375°F. A high-temperature gilsonite blend was compared to cores from the base fluid and sulfonated asphalt.



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High pressures and temps no longer translate into more NPT. High-pressure/high-temperature reservoirs greatly challenge the strength, electronics and chemistry of downhole technologies. To safely and cost-effectively develop your HP/HT reservoirs, Halliburton offers the industry’s most knowledgeable HP/HT experts, capabilities and technologies. What’s your HP/HT challenge? For solutions, go to _____________________ www.halliburton.com/hpht.

Solving challenges.

TM

HALLIBURTON

© 2011 Halliburton. All rights reserved.


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Cores from lime-based mud tested at 275° F. The cores show the decline in erosion and swelling generated with gilsonite material (center). Gilsonite was compared against the base fluid (left) and sulfonated asphalt.

sensitive formations by chemically coating the surface of the wellbore, thereby sealing micro-fractures to prevent, or at the minimum, slow considerably the rate at which a drilling fluid interacts with the formation. Consequently, shale disintegration, or hot rolling, linear swelling, and capillary suction tests do not adequately or consistently demonstrate a fluid’s shale stabilization ability. Triaxial testing under simulated downhole temperature and pressure has evolved as the preferred approach to determine shale stability. Triaxial testing screens the inhibitive properties of various chemicals, along with the effects of contaminants, viscosifiers, and filtration control additives, on the properties of shale inhibitive drilling fluids. A triaxial tester was selected for the latest series of shale stabilization tests, which also included examinations of the impact of the gilsonites and sulfonated asphalts on rheology, filtration, and lubricity coefficients. In a triaxial test, the unit is loaded with a representative shale specimen that has been stressed both axially and radically to simulate borehole stress conditions while the fluid being tested is pumped under pressure through a central borehole. A non-stabilizing fluid sample softens, erodes, and eventually collapses the simulated wellbore. The ability of the fluid to stabilize the shale is expressed as the run time before for the specimen begins to fail. Rather than use shale specimens cut from cores or formation outcrops, the most recent tests relied on reconstructed Pierre II shale samples. Experience has shown that samples reconstructed from drill cuttings or ground shale are more representative of the intrinsic downhole environment, while samples cut from cores often contain small fractures and variations in dip angle and composition, thus generally delivering poor reproducibility. In preparation for the tests, each drilling fluid to be examined according to established formulations. Two gilsonites, one a 350° F (177° C) softening material and the other rated at 380° F (193° C) were to be examined against comparable sulfonated asphalt samples. After the base fluids were formulated, the respective test material was added at a rate of 6 lb/bbl. At that point, the rheological, API fluid loss, and lubricity coefficient properties of the muds were obtained both before and after hot rolling at the appropriate temperatures. A Permeability Plugging Apparatus (PPA), which is designed to accurately stimulate and measure downhole static filtration, was used for the high-pressure/high-temperature (HP/HT) filtration test. Owing to their low specific gravities, both gilsonites and sulfonated asphalts tend to float in drilling fluids. Since a PPA measures fluid loss in the upward position, it is the ideal instrument for testing filtration properties. Both the triaxial and HP/HT tests were con-

ducted only on the fluid samples that had been hot rolled. For the tests, the Pierre II shale test cores were prepared using compaction pressure of 10,000 psi for 24 hrs, then dried and ground sufficiently to pass through a 10-mesh sieve before screened through a 30-mesh sieve. The material retained on the 30-mesh sieve went to prepare the test cores, with enough seawater added to the compaction cell to ensure the water content of the final cores was +/-8.5% by weight. Each of the cores measured 2 x 1 in. with a ¼-in. borehole in the center. The triaxial test conditions entailed: • Radial pressure: 2,500 psi • Axial pressure: 1,200 psi • Pump pressure: 150 psi • Circulating temperature: 125°F (52°C) • Annular velocity: 150 ft/min (46 m/min) • Run time: To failure or maximum of 18 hrs. Both gilsonite samples were hot rolled at 350° F and 375° F before going into the Triaxial Tester. To provide a comparative representation at the appropriate temperature, the sulfonated asphalt samples likewise were hot rolled at 350° F and 375° F.

Results/observations A primary criteria for a drilling fluid additive used to address a targeted downhole condition is to have no detrimental impact on the other properties of the mud system. Although the primary objective of the most recent investigation was to determine whether gilsonites could improve the shale stabilization tendency of the fluids tested or perform equally as well as sulfonated asphalt, the results showed no negative impact on the fluid rheology, lubricity, or filtration properties. As expected, the base lignite/lignosulfonate drilling fluid was the least inhibitive of the four tested, with both low run times and high erosion rates before treatment. When the two gilsonite types were added, the results improved with the 350° F softening point material increasing the run time by 68% with a corresponding 84.6% reduction in borehole erosion. The run time and erosion rate for the 375° material showed an 84.6% increase and 84.9% decrease, respectively, both of which were comparable to the sulfonated asphalt. The PHPA drilling fluid, meanwhile, is considered an inhibitive fluid in that it encapsulates the shale with a polymeric film that effectively slows the capacity of water to wet the shale surface. Similar to sulfonated asphalt, the two gilsonite materials showed a 35.5% and 25.8% increase in the run time for the PHPA base fluid with an impressive 65.4% and 47.6% decreases in the respective erosion rates. However, the comparative results for the tests run on the highly inhibitive KCL drilling fluid samples showed considerably more improvement with the gilsonite additive. While the run times were comparable, the most striking difference was in the erosion rates with the gilsonite-treated samples showing a 58.2% reduction as opposed to a 13% decline for the base mud sample treated with the sulfonated asphalt. Testing on the inhibitive lime-based mud samples showed similar results; although, all samples were hot rolled at a lower 275° F (135° C) to account for the inherent temperature limitations of these systems. While the overall run times for both the gilsonite and sulfonated asphalt samples increased only slightly over the base measurements, the erosion rate for the two gilsonite samples showed higher decreases of 46.6% and 52.1%. Conversely, the decline rate of the comparative asphalt was 47.9%. In terms of shale formation failure times and erosion rates, the tests revealed that the two gilsonite blends can improve on or compete equally with sulfonated asphalt, thus offering a more competitive option for stabilizing reactive shales in a wide range of waterbased drilling fluids.



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The Skarv FPSO turret mooring system: A 5,000-ton challenge

Mamoun Naciri Christophe Jamet Renaud Daran Stein Vedeld

B

SBM Offshore

P intends to develop Skarv field using a turret moored new-build FPSO. The Skarv FPSO has a heading control system because the turret, positioned at 1/3 of ship length aft of the forward perpendicular, has reduced weathervaning characteristics. The Skarv FPSO station-keeping philosophy addresses both Norwegian offshore regulations and BP’s specific requirements, and contains a matrix of load cases to consider in mooring design. The harsh environment at Skarv, along with specific survivability requirements in black ship conditions (complete loss of power for heading control system), result in mooring loads in excess of 5,000 tons. This is a step-change increase from typical values for existing turret moored FPSOs. The Skarv internal turret system is suited for high extreme loads. It consists of a large diameter cylindrical turret structure integrated into the hull. In the lower section the chain table houses double articulated chain stoppers to which the anchor legs connect. ed. Mooring loads transfer from the chaintable through the turret cylinder up to the turret main deck and to the vessel via the bogie bearing system. The axial bogies support the earth-fixed turret weight and vertical loads, and counteract moments. Radial wheels in the bogie support cylinder above the highest water level transfer horizontal loads from the turret to the vessel. In addition to this proven bogie bearing system, an additional lower friction bearing functions when mooring loads exceed a certain level (eg. black ship) to assist the bogie system. The primary purpose of a floating platform’s station-keeping system is to maintain the platform at its location in the field and to keep the risers and dynamic umbilicals within their design limits, thereby protecting the environment and the safety of the personnel onboard. On Skarv, the accommodation, with its temporary refuge, is forward on the FPSO, in line with common practice on the Norwegian continental Location of the Skarv development.

shelf. Skarv is a predominantly high-pressure gas field, so the turret and swivel stack are as far away as possible from the personnel accommodations. Explosion modeling set the optimal layout of the FPSO, and also considered the position of the main power generation module as it is the main potential ignition source. A total FPSO risk review led to a turret position at one-third from the forward perpendicular, behind the power generation module. This means that the FPSO has reduced weathervaning capability. On the Skarv FPSO, the mooring system and a heading control system together provide overall station-keeping. It is imperative to consider both systems in developing a station-keeping design philosophy and associated operating procedures. In the extreme weather of the Norwegian Sea, the heading control system will minimize environmental loads on the hull and mooring system. In normal weather, heading control improves personnel comfort by minimizing vessel motions and ensures the vessel heading maintains an angle with the wind direction to optimize natural ventilation of the process modules. Normally, net forward thrust is not be provided. The Norwegian requirements for mooring design call for a two-line failure, so a robust mooring system is required. Operating with one

Pieter Drijver Volkert Visser

BP Norway line failed is feasible up to relatively severe conditions. A design premise for the heading control system is that no single failure makes it impossible to maintain heading. From investigations by Noble Denton into DP failures, it is known that even with redundant systems like that on Skarv, complete failures or blackouts occur. Following advice from Noble Denton, the project includes the ability to survive a complete loss of power for the heading control system (i.e. black ship) in a 100-year storm in a matrix of design cases for the mooring system.

Design criteria Per the station-keeping philosophy, BP required consideration of three cases beyond the ISO requirements. In particular, the two-line broken case is to be investigated in 100-year conditions to document robustness of the system. Furthermore, consideration of a “black ship” case in 100-year condition instead of 10-year conditions per ISO is included. Finally, a robustness case must be considered in 10,000-year conditions with the station-keeping systems intact (i.e both mooring and heading control systems intact). In these extremely rare conditions, the Skarv FPSO must remain on station, provide a safe shelter to the crew and safeguard the environment. In addition, the project assessed the maximum allowable metocean conditions for a continued production with a single mooring line failure, meeting the required factors of safety for a two-line and three-line failure. The Skarv mooring line shall have a fatigue life of eight times the FPSO service life; i.e., 200 years.

Heading control system Thrusters assist the natural vessel weathervaning and maintain the vessel so that wind incidence is approximately 15º from portside to www.offshore-mag.com • January 2011 Offshore 65


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Skarv field development layout.

enhance ventilation. In storms this requirement can be waived. The use of thrusters reduces forces introduced by wave, wind, and current on the vessel compared to the free weathervaning. Although five thruster units are provided under the hull for heading control, the mooring analyses assume only four are available at any time. Furthermore, the “stand-by” thruster is conservatively assumed to be the most onerous one i.e. that with the largest restoring yaw moment. When considering the “black ship” condition, all five thrusters are not functioning and the station-keeping of the Skarv FPSO becomes fully passive.

Mooring system layout The mooring system consists of three groups of five mooring lines. The angular spread between each bundle is 120° and the angular spread between two mooring lines within a bundle is 5°. One anchor line extremity is secured to the seabed with a suction pile. The anchor line consists of three segments: a bottom chain, a 121-mm (4¾-in.) diameter steel wire rope, and a top chain connected at the chaintable. Both chain segments are 152 mm (6 in.) R3S stud-less chains. The steel wire rope comes with a high-density polyethylene (HDPE) protective sheath for longterm corrosion protection. The pretension in intermediate draft is 1,770 kN. The chains and steel wire rope packages are from Vicinay and Parker Scanrope, respectively. The suction piles have been engineered by SEMAR and fabricated by FCM. Global performance first was assessed

during a model test in January-February 2008. Calibration of numerical tools against these model tests validated their use in the definition of the design loads. Design turret excursions occur for low peak wave periods associated with significant wave heights notably lower than the contour maximum. In contrast, design dynamic tensions occur for sea-states close to the contour maximum. Marine growth has been considered for both extreme and fatigue limit states. The marine growth thickness values specified by default were found early to have significant consequences. Site specific data was collected by BP in collaboration with its Skarv partners to provide more realistic yet conservative depth-dependent marine growth thickness values. The fatigue lives obtained with this field specific data were summarized. Lines 6 to 10 in the south bundle are the most fatigue prone. The ULS 100-year mooring force corresponds to the contour peak significant wave height. The ALS 100-year mooring force is obtained in 100-year “black ship” condition for Hs=16 m. The mooring forces in ULS and ALS black ship 100-year conditions are respectively 2,900 tons and 5,400 tons. The mooring force in 10,000-year conditions is 4,100 tons. These mooring forces are more than twice the value used to design BP’s FPSO Schiehallion turret in the late 1990s.

Turret system design The turret is integrated in the fore part of the FPSO, within a moonpool well. It provides the following three critical functions: • Attachment point to the anchoring sys-

tem effectively provides one element of the station-keeping of the Skarv FPSO • It allows the FPSO to weathervane around the earth fixed turret cylinder • Transfer of production, injection, export, and services fluids through the swivel stack between the earth-bound turret and the weathervaning FPSO. The bottom parts of the turret consist of the lower turret (including the chain table and the cylinder) and the collar structure (including the collar deck). The turret itself is a steel cylinder inserted in a well, formed around the center line of the vessel, one sixth of Lpp fore of amidships. The turret is supported by the vessel via axial bogie arrangements, at the vessel’s main deck level. In normal conditions, the horizontal loads on the turret are transferred by radial wheels above the maximum draught level. Axial bogies and radial wheels form the “roller-based bogie bearing system” of the turret weathervaning bearing system. The axial bogies and the radial wheels are based on a proven turret bearing system design (Ref BP FPSO Schiehallion) that has been in operation since 1998 with the harsh operating conditions of the North Atlantic west of the Shetland Islands. This system also was chosen for previous projects (Capixaba FPSO, P53 FPU, Frade FPSO, Espirito Santo FPSO, and Aseng FPSO) where station-keeping is entirely passive. On Skarv, mooring forces are far beyond any experienced before. Therefore it was decided to implement friction bearing pads with corrosion resistant bearing faces underwater. In extreme conditions they assist the radial wheels and also relieve some of the moments and loads on the axial bogies. In normal conditions these pads are not active so fatigue is not an issue. This lower friction bearing design is derived from previous projects such as the White Rose FPSO operating since 2004 (other projects using friction bearing are FPSO Espadarte, FPSO Brasil, and FPSO Marlim Sul, P33 and P35).

Weathervaning bearing system The turret weathervaning bearing system consists of: • The bogie support structure fitted on top of the vessel well cylinder, which forms the extension of the vessel moonpool • The bogies that transfer the axial turret loads to the bogie support structure. The bogie wheels run on a rail structure mounted on the underside of the collar deck • Radial wheels mounted in the turret bogie support structure below the bogies.



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in the vessel as close as possible to the neutral line (for overall bending) of the vessel, the distortion of the vessel due to hogging and sagging being the lowest at this level. The bogie support decouples the deflections of the vessel from the bearing arrangement. Consequently the deflections of the bogie support structure at the top are minimal, allowing all the wheels to run on the rails and take their share of the load.

Design analysis methods

Skarv turret components.

These wheels run on a rail structure mounted on the turret cylinder • Friction pads sliding (in extreme conditions only) on an Inconel-overlaid bearing face on the vessel moonpool walls. In normal conditions (low loads) the radial wheel and axial bogies transfer loads from the turret to the vessel structure. Turret loads are caused by the vessel induced inertia loads, mooring and riser loads acting at the chain table. In extreme conditions, the friction pads support a large fraction of radial loads, once the initial gap between the vessel and the friction pad(s) closes. The radial wheels and axial bogies will be protected against rain by a closure at the top between the turret collar and the vessel upper deck (weather barrage) and against sea water by a lower sealing arrangement. The well sealing is schematically represented

in between the radial wheels and the max draught level. The axial bogies are on elastomeric pads that allow the bogie units to adjust to small (radial) translations or rotations due to angular misalignments or local deflections. A set of guiding wheels mounted on each bogie unit keeps the bogie aligned with the rails on the turret collar. Both the axial bogies and the radial wheels are installed in such a way that they can be inspected, maintained, or even changed out if necessary. For axial load transfer, the axial rails are integrated in the underside of an outer supporting ring located below the collar deck. For radial load transfer, the radial rails are on the circumference of the cylinder at the radial wheel deck level. Both rails have segments that can be changed out in situ. The bogie support structure is integrated

The friction bearing system withstands the extreme radial mooring loads. It is made up of friction pads mounted on the turret cylinder and running on vessel-mounted Inconel-overlaid rail structures. When there are no loads acting on the turret cylinder, there is a nominal gap between the friction pads and the vessel cylinder. When a horizontal mooring force acts on the cylinder, it deforms and eventually the friction pads contact the race on the moonpool wall. The maximum loads on the upper bogies and the radial wheels will be seen just before contact. After contact a significant fraction of the loading is taken by the friction pads. During extremes the hogging and sagging effects need to be considered. This is introduced in the analyses as a gap variation coexisting with the maximum mooring load. In addition, an integration misalignment (=co-axiality) needs to be represented. By adding the turret co-axiality and the hogging and sagging effects, two groups of analysis have been performed: • Maximum gap opening aligned with mooring load to consider the maximum loads on the bogies and radial wheels • Minimum gap opening aligned with mooring load to consider the maximum loads on the friction bearing system. In addition the effects of tolerances, deflections, stiffness variations, etc, were accounted for considering the following: • Machining and construction tolerances of the vertical and radial rails, and the friction bearing system • Stiffness variations of the bogie supports • Deformations induced by hogging/sagging • Bogie set up flatness.

Acknowledgments The authors wish to thank BP and SBM for permission to share this information regarding the Skarv TMS design. The authors also acknowledge and thank Chris Vogt for his continuous mentoring, guidance, and enthusiasm in the execution of the Skarv project. Editor’s Note: This is an excerpt from a Deep Offshore Technology International presentation. www.offshore-mag.com • January 2011 Offshore 67


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E N G I N E E R I N G , C O N S T R U C T I O N , & I N S TA L L AT I O N

New heavy lift vessel deploys in Gulf Recently-completed catamaran heavy-lift vessel successfully performs first field operation

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ersabar reports that its VB-10,000, a new catamaran heavylift vessel built in the US, has successfully completed its first heavy lift operation in the Gulf of Mexico. On Oct. 7, tugs towed the VB-10,000 through Aransas Pass, Texas, and into the Gulf of Mexico. Just over 48 hours later, on Oct. 9, the vessel used its hook-height systems to bring up a 1,530-ton topside. Consisting of twin 240-ft (73m) tall gantries mounted on custom-built barges, the vessel lifts with four independent blocks that can be controlled either separately or in synchronization. Versabar says that new lift system builds on its proven offshore lift designs, which include the design concepts incorporated in its Versatruss and Bottom Feeder vessels.

Height and lift capacity Over the first four seasons, the Bottom Feeder accomplished over 100 major subsea retrievals (including 31 topsides) totaling over 60,000 tons. The desire for greater hook-height and increased lift

capacity prompted Versabar to contemplate dry-docking the system and modifying it accordingly. These plans were changed by two factors: first, a realization that the proposed modifications would make it difficult to optimize the lift capacity of the Bottom Feeder, and the environment had become favorable for exercising a new-build option. There were numerous engineering, fabrication, and assembly challenges. First was the sheer weight and size of the new gantries. Being more than twice as tall as those of the Bottom Feeder, they would be constructed of 60-in. pipe instead of the Bottom Feeder’s 48-in. pipe, which would render them three times as heavy, approximately 3,400 tons each. This would in turn mean that the system’s two barges would have to be engineered and fabricated with sufficient reinforcement to interface reactions under the gantries. As these factors were taken into account, additional technical issues arose: the size and weight of the gantries meant that new assembly and load-out procedures would have to be devised, as yard cranes would be incapable of lifting or moving the assembled structures.

(Left) Versabar’s Versatruss heavy-lift vessel. (Right) To mate the sections, an “A-frame” was used to perch the upper end of the “narrow-side” assembly.

(Left) Once pinned, the “narrow-side” was then winched upright in a scissoring action. (Right) Versabar engineers opted to use transporters and a determinate tunnel load-spreader to move the 3,300-ton gantries.



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(Left) The transport system was designed so that the end of the gantry was cantilevered out 80 ft beyond the transporters themselves. (Right) The convertible steel assemblies helped achieve the cantilever effect that would enable the transporters to carry the load out over the bulkhead, to the centerline of the second system barge.

(Left) When the second barge was deballasted, the transporters then transferred load to the barges and the VB 10,000 was now free-floating. (Middle) The VB 10,000 was towed out on Oct. 7, 13 months after the first steel was cut and rolled. (Right) In mid-October, the VB 10,000 lifted a fire-damaged 2,500-ton topside from its jacket.

The gantries would have to be constructed in pieces of manageable size and then mated, moved across the fabrication yard, and installed on the barges. These issues were addressed over a period of months as the steel was being rolled and the structural members cut and welded. A high degree of disciplined interdepartmental communication was essential to keep the various aspects of the assembly and load-out procedures on time and on target throughout the project. Each gantry was fabricated in two sections: the designated 870-ton “wide-side” pieces and the 1,550-ton “narrow-side” pieces, named for their respective footprints. Each piece was fitted with two trunions, which were located at the midlines of the centers of gravity in order to create eccentric “hinges” upon which they could rotate when up-righted. Once up-righted, the gantry sections were standing on the bulkhead facing one another. To mate the sections, an “A-frame” was used to perch the upper end of the narrow-side assembly, thus permitting yard cranes to “walk” the wide-side into position to pin the two pieces together. Once pinned, the narrow-side was winched upright in a scissoring action until eight connection points were simultaneously joined.

Versabar engineers had initially envisioned a rail system upon which the 3,300-ton gantries could be moved to the barges. This plan was vetoed in favor of the use of transporters and a determinate tunnel load-spreader built to accommodate the number of transporters that would be required to perform the task. The transport system had been designed that the end of the gantry that was to be placed aboard the barge was cantilevered out 80 ft beyond the transporters themselves, allowing for the heel pins to be “run out” beyond the bulkhead until they were positioned on the centerline of the barge. At this point, the barge was deballasted, to bring the load-spreaders in contact with the pin carriages upon which the gantry was to be seated. Once the gantry was positioned, the transporters released the load, and the gantry welded in its final position. Once the process was repeated for the second gantry, the first system barge had a wide-side and a narrow-side gantry welded into position. The convertible steel assemblies that had served as “in-riggers,” along with the tunnel load spreaders, were now shifted to the outside of the two gantries, achieving the cantilever effect that would enable the transporters to carry the load out over the bulkhead to the centerline

of the second system barge. The process was continued like the earlier load-outs, advancing the trusses into position over the second system barge. When the second barge was deballasted, the load spreaders rose to meet the pin carriages, the transporters then transferred load to the barges and the VB 10,000 became free-floating. Once wiring and instrumentation of the vessel was completed, a test lift using a 2,740ton water-filled barge was performed on each gantry. The VB 10,000 was towed out on Oct. 7, 13 months after the first steel was cut and rolled. Two days later, on Oct. 9, at Vermillion 285, the VB 10,000 lowered its blocks into the sea and retrieved a 1,530-ton topside and jacket section which had toppled during a hurricane and was resting awkwardly on its side. A week later, it lifted a fire-damaged 2,500-ton topside from its jacket and placed it on a materials barge bound for a Gulf Coast salvage yard. This immediately demonstrated the value of the additional hook-height and the additional 50 ft between the system barges. “As difficult as those lifts are,” remarked a Versabar engineer after the second lift, “they seem pretty routine compared to the challenge of assembly and load-out of the vessel itself.” www.offshore-mag.com • January 2011 Offshore 69


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New Topsides, Platforms & Hulls conference meets growing industry demand

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ngineering, design, construction, and installation of offshore production systems will continue to increase as the number of offshore installations increases worldwide. Focusing specifically on this important technology sector, Offshore magazine has launched the Topsides, Platforms & Hulls Conference & Exhibition, the offshore industry’s only event dedicated to the technology associated with topsides, platforms, and hulls for both deep and shallow water. The conference and exhibition will be held Feb. 1-3, 2011, at the Moody Gardens Hotel and Convention Center in Galveston, Texas. The conference will feature a comprehensive technical program that covers the design, engineering, construction, transportation, installation, and modification of topside structures, platforms, and hulls. In fitting with the conference theme of “Where It All Comes Together,” Topsides will feature three days of presentations covering technical issues, business challenges, and future trends, plus showcase an exhibition of products and services from dozens of key engineering firms, contractors, suppliers, and service providers.

Opening reception The conference will begin at 5 p.m. on Tuesday, Feb. 1, with an opening night networking reception in the exhibit hall. The reception is open to all delegates and exhibition attendees and presents an opportunity to join hundreds of colleagues and industry professionals and view the latest technology and innovation in topsides, platforms, and hulls.

Wednesday program The opening plenary session begins Wednesday, Feb. 2, at 8:30 a.m. The featured keynote speaker is Rick McLeod, Vice President, Developments, Americas & West Africa, for Hess Corp. McLeod joined Hess in 2006 as vice president, Production Technology. He was appointed to his current position in 2007. Prior to joining Hess, McLeod worked on the Buzzard Development project with EnCana Corp. and later with Nexen Inc. He spent 21 years with Mobil, later ExxonMobil, in various engineering, advisory, and management roles, including projects in Canada, Russia, and Kazakhstan. The opening session also will include remarks by James Britch, Sr. Facilities Engineering Advisor for Hess and Chairman of the Topsides Advisory Board. In addition, Roy Oelking, President, KBR Oil & Gas will present a special welcome address to delegates and exhibitors.

Session 1 The technical program for Wednesday continues with Session 1, Feasibility/Concept Selection at 10:15 a.m. It is chaired by Jose Vazquez, Bennett & Associates, and Riley Goldsmith, Goldsmith Engineering. Scheduled presentations are: The Octabuoy Platform - Shallow & Deepwater Applications, Robert Shivers, ATP Corp. Magnolia Tension Leg Platform, Z. George Gu, ConocoPhillips. Hullform Selection for the Pony Project, Craig Edel, Hess Corp.

Session 2 Session 2, Concept Definition/Detail Design, begins at 1:15 p.m.

It is chaired by Gary Devlin, Cameron, and Murray Burns, Technip. Scheduled presentations are: Topsides Concept Definition, a Petrobras View, Sergio Libera, Petrobras. Status Report - API RP 14C 8th Edition, William Taggart, Murphy Exploration & Production. Adapting CO2 Membranes for Offshore Topsides, Faudzi Mat Isa and Rick Peters, Petronas and Cameron.

Session 3 Session 3, Fabrication, begins at 3:30 p.m. It is chaired by Carlos Mastrangelo, Petrobras and Bill Pender, McDermott. Scheduled presentations are: Worldwide Capacity – Hulls & Structures; Shipyards & Capability, JP Chevriere, Transmar Consultants. Weight Control on Floating Production Installations, John Andrew Breuer, ABS. Fabrication, Petrobras Strategy, Giovani Nunes, Petrobras. Wednesday concludes with a networking reception on the exhibition floor beginning at 5 p.m.

Thursday program The technical program for Thursday continues with Session 4, Transportation/Installation, beginning at 8:30 a.m. It is chaired by Finlay Baxter, 2H Offshore, and George Gu, ConocoPhillips. Scheduled presentations are: Tahiti, Charles Borland, Chevron. Murphy Kikeh Topsides Installation Using the Floatover Method, Monica Perez, Technip USA.

Session 5 Session 5, Operations, begins at 10:30 a.m. It is chaired by Travis Cagney, Total, and William Taggart, Murphy E&P. Scheduled presentations are: Start-up Commissioning, Trey Lambert, Deepwater Specialists Inc. On-Line Condition Monitoring of Fixed Equipment Using Permanently Installed NDE Sensors, John Nyholt, BP America. Anadarko’s GoM Floater Experience, Gary Mitchell, Anadarko Petroleum Corp.

Session 6 Session 6, Decommissioning/Redeployment Panel begins at 1:15 p.m. and is chaired by Matt Immel, El Paso E&P, and James Britch, Hess Corp. A panel of industry experts from the three industry players; Operator, Contractor, and Regulatory will provide overviews of their activities with a look forward to Gulf of Mexico deepwater abandonments. The panel discussion will include a lengthy Q&A period. Panelists include: Win Thornton, Manager, International Decommissioning, Upstream Business Unit, Chevron EMC; Jan-Willem Leussink, Heerema Marine Contractors; Nederland B.V., the Netherlands; and a regulatory participant to be named. The technical conference concludes at 2:45 p.m. with the presentation of awards and chairman’s closing remarks.



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The business case for investing in safety Automatic ID cuts human error Svein Thorsen

Statoil Doug Woodbridge

S3 ID Group

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he Statfjord field, straddling the Norwegian/UK median line in the North Sea, is one of the largest fields in this sector, at its peak producing over 700,000 b/d of oil. The oil is loaded offshore and taken directly to refineries, while the field’s gas is transported via the Statpipe pipeline to mainland Norway and via the Brent field to the UK mainland. Statfjord has been developed using three production platforms, Statfjord A, B, and C. Each comprises around 250,000 metric tons (275,578 tons) of concrete with around 40,000 metric tons (44,092 tons) of topside processing modules, and accommodation facilities for over 1,000 personnel. With such a substantial offshore infrastructure in a harsh environment, and with the safety and welfare of the crew in mind, Statoil decided in 2006 to improve emergency preparedness across the complex. One key focus was on how to register personnel in an evacuation situation and keep their Emergency Preparedness Management Team (EPMT) fully updated about an evacuation status in real-time. Following evaluation of the in-place “paper”-based systems, management realized there was room for improvement by adopting an Electronic Personnel Registration System (PRS). While musters could be achieved within 20 minutes using conventional techniques, in line with Norwegian legislation, this could prove to be demanding in a crisis. Statoil sought improvements by removing, as far as possible, the human variable and the risk of human error during mustering. In the event of a crisis, Statoil sought to ensure that safety was not compromised through failing to properly account for personnel, so that the search for those missing could take place faster and at the same time prevent the risk of unnecessarily sending rescue teams into a danger zone to find those incorrectly marked as missing. An electronic PRS is not subject to human er-

With over 1,000 workers on the Statfjord production platforms (A, B, and C), Statoil decided to improve emergency preparedness across the complex.

ror under stress, which means the real-time data and counts are reliable. In a crisis, clear communication is critical and improving speed and accuracy of communication can be a lifesaver. In such situations, the role of the radio operator takes on a new dimension. Radio traffic peaks as the crisis develops and the volume of information needed by the EPMT to coordinate search and rescue activity grows exponentially. The PRS specified by Statoil was designed to reduce the burden on the radio operators, further mitigating the risk of human error by streamlining communication and making information directly available in real-time to the emergency teams across all platforms. Statoil has a “No injury/zero harm” target. This safety focus underpins the company’s business ethic – it continually strives to create a safe workplace for all personnel, thus avoiding accidents and occupational illnesses. There is also a strong emphasis on high technical standards and inherent safety in the design and operation of all the company’s plants and installations. The PRS satisfied these criteria, but could bring further advantages in business terms. In addition to minimizing the risk of human error and reducing muster times in a real crisis, the PRS would streamline muster drills to reduce the time required to carry out these necessary exercises and to get personnel back to work more rapidly, thereby cutting lost man-hours.

Another benefit was a reduction in time and lost production costs associated with restoring operations following an emergency muster, which requires that all personnel be fully accounted for before production can resume. Manual “paper”-based mustering techniques can be time consuming both to administer and later to generate post-muster reports. An electronic PRS does this automatically, with a full history being stored and reports generated at the touch of a button.

The Statfjord PRS Statoil selected S3 ID to supply the PRS. This company provides a range of location awareness systems and manufactures the S3 products, which provide solutions from personnel and asset tracking, personnel on board (POB), mustering, access control, safety, and security to travel logistics management. Other attractions for Statoil were that the products are ATEX certified and use patented technology proven in operations worldwide. The PRS supplied by S3 ID provides an automated system using individual radio frequency identification (RFID) active transponder tags allocated to all Statfjord personnel to register personnel during a platform muster. The transponder, which is certified “intrinsically safe for use in hazardous areas,” resembles a watch in size and shape, and is worn at all times to ensure that personnel arriving at their designated muster station are detected as they pass through or by the PRS muster www.offshore-mag.com • January 2011 Offshore 71


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Registering personnel in an evacuation situation is vital part of any emergency preparedness scenario, and an electronic personnel registration system can be a key part of any offshore operator’s emergency toolkit.

station antennas. Currently 3,200 tags are in use. Under normal operation, personnel are issued with a transponder at the onshore heliport. The PRS logs the transponders’ unique identification code to the individual. When a muster is initiated on a platform, the person is registered by the PRS whenever the transponder is detected at the designated muster station. The PRS uses three pairs of redundant PC servers that maintain

an Oracle database record of all muster activities for each platform. The mustering data is gathered from transponder readers at the muster stations. A number of PRS operator workstations are located on each platform’s local area network, as well as the onshore heliport, and have access to PRS information screens. An overview screen shows a summary of an active muster and a number of reports can be generated with current or historical data. In the event of an incident, individual muster lists or incident duties will be available via the PRS operator screen and on hardcopy reports. The heliport onshore has PRS workstation PCs fitted with PRS transponder tag allocators. This enables offshore personnel to be issued a transponder and registered to the PRS on arrival at the heliport. On return to the onshore heliport, the system de-registers each individual and their tag is handed in. A workstation PC and backup tag allocation system is also provided in the Sky Lobby of each installation when required to enable transponder allocation. The PRS has been operational across Statfjord for over three years and has effectively addressed the risks and reduced human error associated with paper-based manual mustering techniques. The system today is a part of everyday offshore life and is an integral part of the safety preparedness arrangements across the field. The technology provides definitive location awareness of personnel from point of departure to personnel on board. It also ensures personnel can be sure their wellbeing is Statoil’s prime concern with the reassurance that should the worst happen there will be the minimum delay in mustering and getting them to safety. Recently, Statoil awarded S3 ID a new contract for 24/7 system maintenance and support.

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w w w. s u b s e a t i e b a c k f o r u m . c o m ___________________________________________________

SUBSEA TIEBACK

FORUM & EXHIBITION February 22–24, 2011 Henry B. Gonzalez Convention Center San Antonio, TX

PennWell invites you back to the 11th annual Subsea Tieback Forum & Exhibition. The Subsea Tieback Forum & Exhibition has become the premier event for one of the fastest growing sectors of the oil and gas industry. Next year’s Subsea Tieback Forum & Exhibition is scheduled for February 22– 24, 2011 in San Antonio, TX at the Henry B. Gonzalez Convention Center. Over 2,500 people and 150 exhibitors are expected at next year’s conference. You can’t afford to miss it.



Supported by:


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Operators elevate well integrity priority Consequences of failure graphically demonstrated at Macondo James King

King Petroleum

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ell integrity has been at the forefront of oil company concerns and the general public’s minds more than ever before, over the past few months. The consequences of losing well integrity (and subsequent well control) have been graphically demonstrated to the world. The executive summary released by BP in September following its own internal inquiry into the Macondo incident determined that the event was initiated by “a well integrity failure.” This failure subsequently led to a further chain of events that resulted in the overall catastrophic outcome. The fall-out from this incident alone could significantly change further the way well integrity is managed, now that the extreme consequences of a failure in this process have been demonstrated. Well integrity management is usually the main focus for an organization during only one part of a well’s life cycle. This period is during the well production (or long-term shut-in) stage, and is often managed by the production or well services group in a company. This procedure may change as a result of the Deepwater Horizon incident. BP has already reorganized, and the new chief, Bob Dudley, has created a new division within the company that reports directly to him, with absolute authority regarding risk control and “sweeping powers” in such areas as well integrity management. Arguably the most definitive statement for the role well integrity plays is from the Norwegian Petroleum Industry Standard – Norsok D010. This particular standard defines well integrity as the “application of technical, operational, and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.” The well integrity processes adopted within the Norsok standard are usually integrated with other internationally recognized standards to form the basis of a generally acceptable well integrity management strategy for an oil and gas operator to adopt. By adhering to a well integrity policy derived from these general standards, an operator can be seen as a socially acceptable, environmentally conscious, and respected member of the international oil and gas producing community. The four stages to be considered throughout the life cycle of a well are design, construction, operations, and abandonment. The ability to implement effective well integrity management processes throughout each stage can vary significantly.

Design stage At the design stage, a blank piece of paper, and unconstrained budget, should yield the optimally designed well to allow the best chance of managing its well integrity. A field development project with a truly “utopian” well integrity concept is unlikely to ever be

Gas leak from conductor.

realized. Project economics make most concepts required to meet this vision largely unfeasible. Unrealistic and unfeasible options are dropped at the concept stage to fit into the economics of the project. The outcome should remain a well integrity strategy that fits the purpose and meets internationally recognized standards. One of the most significant factors that can influence well integrity later in a well’s life is often incorrectly accounted for at the design stage and generally not a fault of the engineers. This is the period of time the well will exist (as a producer, injector, or suspended) until abandonment. The life of a well is nearly always designed for far less than the actual period of time the well will be in service. Endless examples exist where something has been engineered for a pre-determined life span yet it still exists far beyond its intended time. Most aging structures within an oil and gas producing asset will still be operating long after the original design life. In an aging well stock, a loss in integrity can be difficult to observe. Most problems are subject to diagnosis, or likely inferred. A structural failure on a topside jacket is easily identified, a deep-set liner-hanger failure in a well not so straight forward. Some easily identifiable losses in well integrity occur, but the situation downhole shows a less dramatic example. A gas leak from a conductor on a well more than 20 years old would be an example, and it is easily observable and relatively straight forward to repair. Well design should ensure that the objectives for which it is being constructed can be met. Clearly, a well needs to be capable of delivering its designed purpose. Equally important is the ability for the integrity of the well to be maintained and to allow remedial actions. A well constructed with fully cemented solid foundations and barriers suggests a sound basis for well design. However, are these attributes particularly favorable for well integrity management purposes? If cement bonds, sealing devices, casing, and formations remain intact, well integrity problems should be largely irrelevant. In adopting design principles such as these, problems can occur if well integrity is lost at some stage. Quite simply, the space available for dynamic motion (fluids to expand) anywhere other than the in-



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ner annulus is very limited in such an example. Options for remedial repair outside of the inner annulus are even more limited.

Well construction The construction part of the life cycle is the key area where the well integrity can be determined. The best chance of minimizing integrity problems is during the construction phase. Change management is of fundamental importance in applying appropriate control processes during well construction. If the basis of design has determined discrete criteria, any associated change must be highly controlled. Failure to do so may have the ultimate detrimental effect on the long-term integrity status. Many organizations see significant resources allocated to ongoing well integrity management issues as a result of changes made at the well construction stage. Change management must include basis of design and risk reviews.

Operations The key difference with aging wells is that failure modes are more likely to occur. (By aging, it is assumed the well is beyond the initial design life.) The escalation scenario for a well integrity situation to get worse in an aging well is far more grim. Annular pressure management is one area where controlled monitoring can allow potential well integrity problems to be identified early on. While a well is being constructed, there are implicit control processes in place. It is important to understand differences between the construct and operating phases. Using results obtained during the drilling of a well may not be suitable during the operating phase. A drilling maximum allowable annulus surface pressure (MAASP) for a hole-section is not the same as the annuli MAASP to be used during the operating phase. It is uniquely different in derivation and eventual use. When well construction is complete, providing one knew where the top of cement was for each section, the completion brine/annuli fluid type and density, tubing/casing grades, formation strengths, and associated equipment pressure ratings, a fairly precise MAASP can be derived as a control process for any well. For an aging well, uncertainties when conditions change is the overlying concern when adopting well integrity control processes, such as re-determining MAASPs. It is for this reason that worst-case assumptions are set as the starting point in well integrity control processes. When the pressure changes in annuli in an aging well, it most likely is a consequence of corrosion or cement degradation. In a worst-case scenario, one should assume that cement degradation has occurred to the extent it may have to be disregarded as a pressure containing medium and that the differential fluid hydrostatic pressure supporting the casings is no longer near equal. This condition could occur as a result of a brine or gas influx from an overlying aquifer or deeper producing zone. It could even be a consequence of changing a well’s status from that of a natural producer to artificial lift, specifically that the Aannulus fluid has been replaced from a liquid to a gas. Some organizations may take assumptions further

Well schematic, cemented to surface.

and create more pessimistic worst-cases. Generally, the more pessimistic the assumptions, the lower the operating boundary of the well when in-service. Evacuated tubing and casing scenarios can be used, more commonly so with tubing. In extreme cases, assuming vacuums are applied may be considered. In complicated well designs, such as deepwater HP/HT wells, where gas cushions and other precautions may be used, the importance of realistic absolute worst-case scenarios cannot be overstated. Things can change very quickly in these types of wells, especially when gas is the dominant fluid. There cannot be hard and fast rules in determining well integrity control processes during the production phase. There must be flexibility depending upon associated risk levels. Every well, especially an aging one, should be treated on an individual basis. Appropriate well integrity management is a case of setting a control process (deriving the figures), with sound reasoning, competent engineering judgement, and ensuring all assumptions are clearly implicit from the end result. You should also undertake independent verification and internal technical assurance. This is the external additional safeguard to assure that the control processes adopted by an organization are sensible and in-line with favorable recognized international standards. Other assumptions to consider when deriving control include when a field undergoes facilities compression and subsurface compaction (especially in a carbonate environment).

Well abandonment Abandonment is without doubt the most overlooked stage of a well’s life cycle. Most field development plans (FDPs) are required to address an end-offield strategy, which should include abandonment. It is, however, often left as “to be confirmed” within the scope of most FDPs. As the focus and profile of well integrity increases, statutory authorities are less likely to accept this. In the future, appropriate abandonment strategies will become a stricter requirement before production licenses are granted in many more countries throughout the world. The possible recovery of hydrocarbon-bearing formations to virgin pressure should be considered as a given in developing an abandonment strategy, unless it can be categorically proven otherwise. The deterioration of some well components over time, post-abandonment, may be difficult to quantify, but must somehow be accounted for. Again, setting control processes with sound reasoning, competent engineering judgment, and ensuring assumptions are implicit should ensure that where best practice is adhered to, the principle of reducing risk to as low as reasonably practicable has been achieved.

Acknowledgment This article is based on a paper presented at the Offshore Middle East Conference & Exhibition, Doha, Qatar, October 2010.

The author James King is a petroleum/well engineer, with over 25 years of experience in the delivery of various large scale oil and gas field development and abandonment projects, including subsea. He holds professional titles as a chartered physicist, chartered scientist, and chartered engineer. He is a member of the Institute of Physics, and holds a BSc (Hons), and Post Graduate Diploma in Management awards. He has worked for major operators in various petroleum/ well engineering roles, and as a field development project manager, wells/reservoir team leader and drilling manager. www.offshore-mag.com • January 2011 Offshore 75


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Wireless communication enhances subsea production monitoring

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ireless technology is established as a powerful communication and network tool in many surface applications. The adoption of a wireless approach to producing highly instrumented subsea equipment removes the physical cabling requirement; and this, when combined with the associated reduction in cost, makes it far more practical and cost-effective to deploy and maintain a far greater number of sensors. The technology may also offer benefits for temporary setups, during system installation; and in workover operations. In developing a wireless network approach for enhanced subsea production monitoring systems, it is important to ensure that the approach supports the instrumentation required. Such instrumentation may include a range of devices with differing control and output data requirements. This may range from low data rate temperature sensors to high data rate video systems. For this reason it is necessary to include a wide communication capability. In addition to the device data requirements, there will be a requirement for short-range wireless communications for on-system applications, such as the subsea tree, and longer range communications for pan-field applications like Intelligent energy system measurement requirements for a subsea tree.

John Mulholland Daniel McStay

FMC Technologies Ltd. monitoring along risers. The complexity of the metal structures of subsea wellheads and trees, along with the associated flow lines, pumps, and valves, poses a challenge for wireless systems. In developing the wireless network for subsea production systems, it is important to account for the complexity of the metal structures and to ensure that the wireless technology used and network design minimize potential problems of interference reflection, background noise, etc. Due consideration also should go to data rate requirements for each instrument, in order to minimize the power consumption of the wireless sensor.

Wireless technology Surface wireless systems commonly use radio frequency transmissions, although optical systems are used often for high data rate pointto-point communications. In contrast, historically the principal wireless communications technique underwater is acoustics. Its capabilities,

practicalities, and limitations are well known. Acoustic communications have low to medium data rates and are limited by background noise as well as noise from subsea equipment such as pumps. Data rates for acoustic communications are limited to around tens of thousands of bits per second (bit/s) for ranges of a kilometer and less than a thousand bit/s for ranges up to 100 km (62 mi). Subsea acoustic communications are also affected by temperature gradients and air bubbles in the water. Still, subsea acoustics are efficient at long-range subsea communications and have relatively low power consumption for their range. The ability to communicate over long distances subsea is perhaps acoustic technologies’ greatest advantage. However, the speed of acoustic waves in sea water is approximately 1,500 m/s. This means that for longrange communication there is high latency. Latency constitutes problems for applications requiring real-time response, synchronization, and multiple-access protocols. Considerable effort has been directed to develop underwater wireless acoustic networks. However, the most common commercial acoustic modems are designed primarily for point-topoint communication rather than for network operations. There are challenges to be addressed to produce practical, low cost ad hoc network systems. These include high bit error rates due to multi-paths scenarios, complex architecture, path redundancy, and increased network functionality. With a large number of sensors, the limited bandwidth may be critical. Advanced processing and system designs are being developed to enable higher data rates, more robust links, and to address latency, reflections, and ray divergence. Therefore, it is not surprising that alternative subsea wireless technologies have been attracting interest for subsea sensor networks and particularly for highly instrumented subsea production equipment.

Optical wireless Optical wireless or free space optical (FSO) communications have been used in surface applications for decades. In particular they have found favor in point-to-point secure high bandwidth (Gbit/s) links over ranges of up to a few kilometers. These capabilities make FSO potentially useful for subsea wireless network applications. For subsea applications, the technology essen76 Offshore January 2011 • www.offshore-mag.com


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tion and limited data rates, with typical performance being 100s of kbit/s over a few meters and 2 kbit/s at 100 m. MI is immune to scattering and reflection, and can penetrate water, ice, earth, and rock. These features mean MI can provide wireless communications where traditional wireless systems cannot.

Power supply

Schematic of an integrated subsea wireless system comprising acoustic, optical, and magnetic induction systems.

tially is the same as for surface systems, but the operating wavelengths and ranges are restricted. These are determined by the optical properties of the sea water at the location. In addition to water, which absorbs strongly towards the red and infra-red, there are a number of variables that impact the optical properties of sea water. These include dissolved salts such as NaCl, Na2SO4, and KCl typically found in sea water, that absorb light at specific wavelengths. The relative abundance of chlorophyll and plankton also impacts the overall absorption properties of the seawater, as will turbulence and disturbed sediments. The lowest absorption for typical seawater occurs in the 400–500 nm wavelength region, which is the blue-green region of the visible light spectrum. As well as absorption, light propagating through seawater is subject to Rayleigh scattering. Scattering not only contributes to the overall attenuation of the light propagating in the sea water, but multi-scattering also causes optical pulses to widen in the spatial, angular, temporal, and polarization domains. To be effective subsea FSO systems need to operate in the blue-green spectral region. Recent advances in light emitting diode (LED) and laser diode technology have produced efficient, compact, long life time optical sources emitting in this range. Similarly, there are a number of efficient optical detectors for these operating wavelengths. In addition to the band widths achievable from LED or laser diode sources, the choice of optical source for a particular application depends on the angular spread, or beam divergence. For high bandwidth point-to-point communications, laser diodes generally are preferable. For lower bandwidth applications involving multiple nodes, the greater angular spread of LEDs may make them preferable.

Radio frequency wireless Radio frequency (RF) wireless networks are used extensively for surface through air applications. The transmission of RF electromagnetic waves through sea water is, very different from that through air due to the

high permittivity and electrical conductivity of sea water. These properties mean RF signals are strongly absorbed in sea water. However, the transmission properties of water depend upon the frequency of the RF signals. Newer subsea RF communications systems that use digital technology and signal compression are capable of data rates of 100 bits/s up to 100 m and up to 100 kbit/s over 10 m. These data rates potentially make the technology useful for subsea wireless sensor networks for production monitoring applications. However, these systems have high power requirements on both transmit and receive sides, making them less practical in a deployable wireless solution. Recently preliminary reports have surfaced about higher-frequency subsea RF systems that use a less well-known feature of throughwater transmission (Debye relaxation). Although the near-field energy of such a system is absorbed rapidly by the water, a weaker farfield component with, for example a 5 MHz signal, may be detected over tens, and potentially hundreds of meters. Subsea RF communications are immune to acoustic noise but can be impacted by salinity variations in the sea water and by subsea RF interference from electrical equipment. In developing an RF wireless network for hydrocarbon production systems, it is important to account for complex metal structures and to ensure that the wireless network design minimizes potential problems associated with interference and reflection.

Magnetic induction wireless Magnetic induction (MI) based wireless communications systems are capable of working in a range of environments. MI works by generating, modulating, and detecting magnetic fields. MI transmitters generate a highly localized dipole field with no far field (RF) emissions. This eliminates possible detection outside of the operating area. However, existing MI communications systems suffer from high power consump-

One key challenge to subsea wireless systems for enhanced production monitoring is the powering of both the sensors and wireless communications. The obvious option is an energy storage device, battery, or power storage capacitor for each wireless sensor node. The limited storage capacity of such devices may not be appropriate for long-term subsea deployment, which could reach 25 years. Incorporating subsea energy scavenging or generation into each wireless sensor or node may be a reliable option. Energy scavenging may be augmented by energy storage within the sensor or node. Although still at a relatively early stage of development, there are energy scavenging or generating techniques that might be suitable for subsea wireless systems.

Integrated systems From this discussion, it can be seen that all the wireless technologies have advantages and disadvantages for subsea application, but that none is capable of satisfying all the requirements listed. In practice, it is necessary to adopt an integrated approach using several wireless technologies. The exact composition of a given network depends on the local conditions (application geometry, turbidity, background noise levels, network structures required, available power, etc.) and data requirements. For example, a FSO network may provide short-range, on-system high bandwidth communication networks and acoustics to communicate with remotely located devices. It should be possible to create effective wireless sensing networks to support enhanced production monitoring. In operation, the wireless network will meet with a wired communications and control backbone that may be fiber optic or copper based that can transmit the data to shore. An integrated subsea wireless sensing network will have wide scale applicability in areas such as: • Asset integrity and flow assurance monitoring • Communication to intervention systems • Back up communication channels • Retrofit and repair solutions for sensors/jumpers • Remote/temporary abandoned structures • Environmental monitoring systems. www.offshore-mag.com • January 2011 Offshore 77


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FLOWLINES AND PIPELINES

Survey assesses geohazards for record subsea pipeline

James Nicholls

Flintshire Geoscience Ltd.

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he Galsi pipeline across the Mediterranean Sea will transport natural gas from Algeria to Sardinia and mainland Italy once completed. Parts of the 560 km (348 mi) offshore route encounter difficult seabed morphology, descending and climbing steep slopes in water depths approaching 3,000 m (10,000 ft). Variable and potentially unstable soil conditions exist on the route. Secure engineering design and stable pipeline routing call for detailed knowledge of seabed structure and topography, plus an insight into the geotechnical properties of the soils on the seafloor. Galsi is an acronym from the Italian Gasdotto Algeria Sardegna Italia. The project company Galsi S.p.A. was incorporated in 2003 to promote and manage construction of the proposed new natural gas connection from North Africa into the Italian gas grid. Galsi’s shareholders are Sonatrach from Algeria, Edison and Enel from Italy, Italian utility Gruppo Hera, and Sfirs, the regional financial institution of Sardinia. Late in 2008, these partners were joined by Snam Rete Gas, Italy’s biggest natural gas distributor, which is to build, own, and operate the links to connect Italian customers to the energy supplies of the Galsi pipeline. In 2007, Galsi commissioned Fugro to undertake a detailed marine route survey (DMS) comprising a series of investigations along the entire marine route – from the site of a proposed compression station near the Algerian coast to a beach landfall facility in the south of Sardinia, and from Olbia in the north of the island, across the Tyrrenhian Sea to Tuscany.

Optimum route alignment The DMS findings were needed to facilitate detailed engineering design and to provide the basis for route engineering input to the construction tender process. The objective of the offshore, near shore, and landfall route surveys was to acquire data to support optimum route alignment and mechanical design of the proposed pipeline as well as to satisfy requirements during pipeline installation and throughout the design life of the system. Continuous route coverage was required from the deepest water, through the surf zone and across the beach to the location of proposed onshore processing facilities. The reporting and charting requirements alone

3D rendering of topography and sea-bed morphology on the pipeline route section between Algeria and Sardinia. The pipeline route (in red) descends and ascends steep and potentially unstable slopes on the continental shelf margins to cross the Mediterranean Sea in water depths approaching 3,000 m (10,000 ft).

called for detailed planning, careful management of a huge range of data types, and a large program of geotechnical laboratory testing. The DMS was split into packages, each with a pre-agreed timetable and a pre-defined sequence to allow route details and investigation requirements to be modified in light of earlier findings. Galsi wanted to refine the proposed pipeline route on a continuous basis as the survey progressed and as data was processed. Fugro assisted Galsi by providing full access to all data collected during the survey in order to assess site conditions, to perform onboard engineering evaluation, and to adjust the survey program as necessary. The preliminary route found the deepest water between Algeria and Sardinia, where 20% of the route lies on the abyssal plain at depths of around 2,850 m (9,350 ft). Moreover, descents from continental shelf to deep water were steep and difficult, requiring careful route selection to ensure pipeline stability and security. The Sardinian continental slope sections on both the Algeria/Sardinia and Sardinia/Italy segments were problematic and required additional offshore reconnaissance surveys to determine optimal route alignments. These route sections involved variations in seabed level as great as 2,500 m (8,202 ft) over distances of 50 km (31 mi) – an average gradient of 5%, with steeper slopes over shorter segments. The offshore hydrographic and geophysical surveys were completed first, giving priority to optimization surveys in the above areas, continuing with feasibility surveys in other

more difficult areas identified during reconnaissance, and ending with a high-definition survey along the entire offshore section. To complete the program in water depths greater than 90 m (375 ft), Fugro mobilized the Echo Surveyor AUV from the support vessel Geo Prospector. AUV technology mapped the route with high resolution previously available only in modest water depths. The AUV carried a high frequency multibeam echosounder, a sub-bottom profiler, and a high-resolution side-scan sonar for a full geohazard assessment to be performed along the deepwater sections of the route, particularly in areas with difficult seabed relief or evidence of soil instability. For acquisition in depths less than 90 m (295 ft), Geo Prospector has a suite of hull-mounted and towed hydrographic and geophysical survey sensors delivering multibeam echosounder, side-scan sonar, and shallow sub-bottom profiler data, plus magnetometer data as required. Geo Prospector also undertook a seismic geohazard survey along sections of the route to a depth of approximately 1,000 m (3,280 ft) below the seabed to identify the sub-seabed structural geology for further geohazard analysis, and to locate and identify major fault zones and discontinuities that might impact pipeline integrity. The final element in the program was a series of surveys to provide additional detail at points where the proposed Galsi route corridor crossed existing cables and other pipelines, and to investigate any obstructions found within the corridor during the high-definition route surveys. These special surveys involved use of deep-



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water work-class ROVs, rated to 3,000 m (10,000 ft) operating depth, deployed from the Fugro ROV support vessel Skandi Inspector. Each cable or pipeline within the route corridor was tracked over the full corridor width using ROVmounted video cameras and a cable tracking system. Measurements were made to confirm the orientation of the cable or line, its depth of burial, and the exact crossing co-ordinates.

Geotechnical investigations Onboard assessment of the hydrographic and geophysical surveys enabled Galsi to define a preferred route for the pipeline over all but the near shore sections. The next stage involved detailed geotechnical investigation of the route center line using of coring, sampling, and in-situ tests. To fully evaluate pipeburial options on the continental shelf and also soil stability conditions on the continental slope, the specification called for direct sampling using gravity, piston, or rock coring methods together with in-situ penetration tests made by peizo-cone (PCPT) and T-bar. The long piston corer and PCPT/T-bar were the prime sampling and testing tools on the continental slope. Because of the nature of the soils, 15-20 m (49-66 ft) penetrations below seabed were required, even in the deepest water. These investigations called for some of the largest and heaviest seabed equipment in Fugro’s geotechnical inventory, including a SEACALF, wheel-drive, cone penetrometer test (CPT) frame generating 50 kN (11,240 pound force) of thrust and the STACOR piston corer with a 20 m (65 ft) core barrel. This hardware was deployed from the dynamically positioned geotechnical ship Bucentaur. SEACALF incorporates a self-leveling mechanism for in-situ soil testing even on uneven seabed with slopes approaching 5°. The STACOR piston corer acquired undisturbed samples to assist identification and aging of geohazards detected by geophysical techniques in the initial phase of the DMS. These geohazard studies benefitted greatly from inclusion of data interpreted from 50 or more box cores also acquired along the route. Closer to shore, a second geotechnical vessel, Fugro Commander, deployed sampling and testing equipment suitable for water depths down to 200 m (656 ft). This included a vibrocoring system for recovering ”undisturbed” soil samples in sands and stiffer clays, as well as additional equipment for coring and in-situ tests. At the landfalls, a coastal geotechnical jackup platform and shallow draft near shore survey vessels were mobilized to ensure a continuous dataset in the transition zone between offshore and onshore. Onshore, personnel using specialist equipment gathered geophysical and geotechnical data between the landfalls and compression station sites, away from the beach. Once Galsi had determined an offshore

Geohazard profile reports.

approach to each landfall, Fugro mobilized an inshore survey vessel to conduct hydrographic and geophysical surveys in waters of less than 20 m (65 ft). The objectives were similar to those for the deeper water surveys but emphasized data to support engineering design for potential shallow-water trenching needs and specific pipeline installation methods between the landfall and near shore areas. In shallow water, Fugro offered a marine seismic refraction system to complement data acquired by seismic reflection profiling. To complete the picture, a self-elevating jackup platform was sent to each of the landfalls to complete a series of geotechnical boreholes to approximately 10 m (33 ft) below seabed. The ground investigation included drilling by cable percussion and/or rotary methods, borehole sampling/coring, and standard penetration tests for in-situ soil. The survey and geotechnical field work took about nine months to complete, involved 830 days of site work, and, at various times, required more than 500 people on site and 14 separate survey spreads. Data integration and production of the detailed charts, reports, and geohazard assessments was completed for the most part by Fugro GeoConsulting in Great Yarmouth, UK. Since this project concluded, Galsi has contin-

ued to work with the data, charts, and reports to finalize project engineering and to obtain approvals necessary to move forward. Galsi’s focus has been to select a route giving the most reliable installation and with the least impact to environment and infrastructure. The deepwater geoscience data provided by Fugro enabled the project engineering team to evaluate seabed geological conditions and scenarios, and to model active and recently active processes. This established an understanding of potential impacts to the project engineering and enabled a thorough geohazard risk analysis. By critical review of the mapped and modeled features and careful selection of the pipeline route, the pipeline was confirmed to be in the most favorable alignment in relation to irregular or potentially unstable seabed. This engineering evaluation commenced most importantly during the early part of the AUV survey when Galsi engineers were offshore with the Fugro geoscientists to develop and monitor initial geohazard interpretations and review route options for final approval onshore. The field data and final interpretations provided by Fugro included detailed geological description and age dating of key soils. Using this information as a reference, a number of geohazard workshops were initiated by Galsi. These hands-on sessions let Fugro geoscientists discuss and debate interpretations, and Galsi engineering and geohazard consultants, including independent peer review specialists, to assimilate the results and assess their engineering significance. Galsi has provided soils and geomorphology information at consistently high resolution, extending from the proposed onshore facilities throughout all offshore and deepwater route sections. Galsi engineers have finalized initial design parameters, risk assessments and intervention requirements, which will permit the detail design engineers, soon to be appointed, to confirm seabed characteristics and requirements for pipeline installation. In addition to engineering design, the imaging of seabed features and detection of debris in all water depths, allowed the early consideration of potential environmental impact and screening for archaeological significance. This allowed the appropriate specialists studies to be performed by Galsi for the regulatory permitting process. While Galsi continues through the authorization phase, the initial engineering work is complete, and a positive conclusion to the review of the Environmental Impact Assessment, by the Italian Ministry of the Environment is expected very soon. This will lead to a final authorization to build from the Ministry of Economic Development. At that point, the Galsi partners will be in a position to authorize a final investment decision and to start the construction phase. www.offshore-mag.com • January 2011 Offshore 79


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Mitigating deepwater pipeline buckling and axial stability Recent case study examines ways of improving the stability of high-pressure/high-temperature flowlines Amitabh Kumar Brian M. McShane

INTECSEA, WorleyParsons Group

I

ncreased deepwater development over the last decade, together with industry monitoring of high pressure/high temperature (HP/HT) flowlines, reveals the critical nature of global stability in the management of flowline buckling and axial stability of these systems. Global stability is one of the most important design considerations for a flowline system. This concern represents the potential for a flowline to move either axially along its length, laterally from its installed condition, or vertically causing flowline upheaval. Large compressive forces induced on a flowline system once operational causes this phenomenon. Contributing factors to this phenomenon include seabed terrain, boundary conditions, and operating strategy. With more than 25,000 mi (40,234 km) of pipeline in the Gulf of Mexico alone, global buckling and axial stability of production flowline systems in water depths between 3,000 ft to 10,000 ft (914 m to 3,048 m) presents an industrywide concern for flowline integrity. Short flowline systems, generally in a range of 3 to 5 mi (4.8 to 8 km) in length, with the complexity of HP/HT conditions, can translate axially or “walk” as a result of normal operational start-up and shut-down. More recently, however, flowline systems which incorporate wet insulation and which have comparatively low specific gravity also show a high propensity to walk, even for systems 15 to 20 mi (24 to 32 km) long. INTECSEA has completed a case study on these deepwater systems, identifying specific design aspects of wet-insulated flowline axial stability and associated analysis, and suggesting mitigation options. Flowline/pipeline systems installed on a steeply sloping seabed compound the problems and underscore industry resolve to remedy these issues. Finite element analysis of wet-insulated systems on steep slopes helps quantify the

The industry has several deepwater flowline systems routed across challenging seabed features with seabed slopes ranging between 5º to approximately 40º.

impact of cyclic thermal and pressure loading on a given flowline.

System impacts The impacts of deepwater buckling and upheaval on deepwater pipelines and flowlines can be significant, including: • Significant cumulative end expansions greater than 20 ft (6 m) can occur until a system reaches a point of stability • Flowline system response is characterized by interaction of the seabed slope, flowline expansion, lateral displacement, and effect of the thermal/pressure gradient and thermal cycling • Selection of a nondirect or somewhat “meandering” flowline route, combined with full-scale, three-dimensional finite element modeling, can mitigate significant end expansions • Most favorable routing for a deepwater flowline system design may challenge developers, as some seabed features are not avoided easily and can impose significant cost increases on a project • Flow assurance performance requires that many flowline systems have good thermal properties, or low U-value; i.e., overall heat transfer coefficient. Thermal insulation applied on the outside of the flowline can facilitate this performance • A common system configuration uses wet insulation applied on the outside of the flowline and exposed to the marine envi-

ronment. A single or multilayer coating system of five to seven layers is common • Low specific gravities of systems can result in a low flowline submerged weight and, consequently, low axial frictional resistance • Project terrain combined with low systemspecific gravity, and typical production temperature and pressure conditions makes the flowline system susceptible to global lateral buckling as well as axial creep. The INTECSEA case study addresses these, given the following flowline parameters and conditions: A wet-insulated production flowline system (D/t~17, inlet temperature = 200° F/93º C ) routed across an area of steep slope with a product-filled specific gravity of 1.5 and approximately 20 mi ) in length.

Problem overview The industry has several deepwater flowline systems routed across challenging seabed features with seabed slopes ranging from 5º to approximately 40º. Notable projects that have negotiated such features include: • BP’s Atlantis project over the Sigsbee Escarpment in the Gulf of Mexico • Norske Shell’s Ormen Lange project over the outer continental shelf in the North Sea • Medgaz – developed by a five-company consortium – across the Mediterranean Sea from Africa to Europe • Gazprom/Eni Blue Stream across the Black Sea.



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Local gradient (deg)

20

Local seabed features

15 10

Seabed profile

5

-5 -10

Depth ~2,500 ft

-15

Distance (~20 miles) For the case study, INTECSEA plotted route profile and relative seabed gradients with average gradients ranging from 5º to 10º.

Low-pressure and low-temperature flowlines or export pipelines are comparatively easy to manage because of lower axial force. A long HP/HT flowline system – fully restrained axially rather than a short flowline – experiences end-expansion and potential for high stresses resulting from lateral displacement at natural seabed features. In contrast, a partially restrained system – where available seabed friction resistance is not sufficient to balance the compressive force in the flowline – encounters design complexities. Aspects of this system include large transient cumulative expansion and a propensity for the entire system to translate gradually from one end – hot or cold – to the other end – hot or cold – after each cool-down/restart cycle, causing the walking phenomenon. While walking normally is associated with short flowlines, wet insulated systems ranging up to 20 mi (32 km) long also have these issues. This primarily results from lateral buckles – engineered or natural response – that separate flowline response on either end. In effect, the flowline behaves like a partially restrained system similar to a short flowline. Analysis of such a system on a flat seabed – including effects of sloped seabed or riser-bottom tension – is a common design approach to quantify flowline walking behavior. Modeling provides a time-efficient solution convergence and reduced computation time and cost. Limitations to such modeling techniques, however, include seabed undulations, potential flowline spans, irregular bathymetry, and narrow opportunities to identify true flowline response. Selection of the most appropriate design and mitigation requirements is thus limited as well. For the case study operating conditions, the system is prone to lateral buckling because the compressive force of the flowline is higher than the critical buckling initiation force. The associated flowline route topography is a typical seabed phenomenon in deepwater areas with average gradients ranging from 5º to 10º over a distance of 1 to 3 mi (1.6 to 4.8 km). Designers can apply a staged approach to assess flowline parameters, with the initial

step taking an analytical solution. An initial finite element analysis using two-dimensional finite element modeling, followed with detailed three-dimensional finite element modeling of the actual flowline route, is preferred. Flowline analysis finite element software (ANSYS) follows in a sequence of load steps, beginning with an as-laid or empty condition and proceeding toward flooded, hydrotest, and operating conditions. The computed analysis includes seabed and flowline profiles, spans, stresses/strains, axial forces, and flowline displacements. In the case study, water depth ranged between 200 ft (61 m) at the shallow end and 2,500 ft (762 m) on the deep end. The route also had three curves along its length. The average seabed gradient was approximately 8º to 10º across a 3-mi (4.8 km) slope, with the maximum gradient of approximately 20º near the top of the slope.

Preliminary analysis The analytical solution shows end expansions of 25 ft and 16 ft (7.6 m and 4.9 m) on hot and cold ends, respectively. The two-dimensional analysis shows end expansion of 12 ft and 3 ft (3.65 m and 0.9 m) on hot and cold ends, respectively. The two-dimensional analysis shows that uncontrolled lateral displacement would overstress the pipeline. Following these preliminary assessments, with its own limitations on predicting the true flowline response, INTECSEA created a full three-dimensional finite element model that includes pipeline route bathymetry and route curves. This model provides improved global and local predictions of flowline response and associated stresses, expansions. The model also includes pipeline route lay radii, or curves, ranging from 5,000 to 8,000 ft (1,524 to 2,438 m). More realistic predictions for end displacements are approximately 6 ft and 3 ft (1.8 m and 0.9 m) at the hot and cold ends. Hot-end expansion, compared to two-dimensional assessments, is nearly 50% lower, whereas the cold-end expansion remains more or less unchanged. Axial force reductions from the previous

analysis result from more locations or instances of lateral flowline displacements. This analysis shows a maximum lateral displacement of approximately 40 ft (12 m). These lateral displacements are acceptable because the flowline is not near seabed features that would contribute to its lateral instability. Reduced stress levels at the displaced flowline sections were confirmed with a local buckling check, per DNV-OS-F101. The local buckling unity check along the entire flowline length was within the acceptable limit.

Seabed intervention To evaluate the impact of engineered initiation sites for lateral displacement, INTECSEA included simulated sleepers, or pre-laid pipes, which facilitate flowline displacement. End displacements are 6 ft at hot end and 3 ft at cold end, as predicted by the 3D assessment without pre-installed initiation sites. The study examined the axial force and lateral displacement along the flowline length. The artificial displacement units induce the flowline to displace at 15 locations; 11 of them similar to the natural displacement locations seen in the previous analysis. These displacements indicate pre-installed sites are not required as long as the flowline displaces naturally. In some instances, however, intervention systems may be installed to facilitate expected flowline response, as non-engineered lateral displacement may overstress the flowline. A maximum lateral displacement of approximately 35 ft (10.6 m) is observed, and maximum lateral displacements within 5 mi (8 km) from the hot end range from 25 to 30 ft (7.6 to 9 m). Transient finite element simulations focus on flowline cumulative expansion and whether the entire flowline system would translate independently on both ends, hot or cold. INTECSEA created an ideal, or best-option, temperature profile for the transient heating cycle and cooled the flowline system uniformly along its length. During cool-down, the effective axial force changed direction from compressive to tensile on a partially restrained system. A component of lay tension also may be included in the effective force.

Transient cycling assessment The transient cycling assessment captures the transient response when the flowline displaces at specified locations and is especially critical within 3 mi (4.8 km) of either end. Importantly, the assessment shows that seabed intervention improves the overall expansion, which reduces significantly during the transient cycling stage. Controlled flowline displacement at pre-installed and www.offshore-mag.com • January 2011 Offshore 81


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today’s tomorrow’s maintenance performance September 20 – 22, 2011 Mo ody Gardens Hotel & Convention Center Galve ston, Texa s w w w.ogmtna .com

Owned & Produced by



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BUSINESS BRIEFS

People Xodus Group has appointed Dr. Anthony Millais as principal environment consultant. Millais will be based at the company’s London offices. Shell has appointed Dirk Smit as chief scientist for geophysMillais ics, John Karanikas as chief scientist for reservoir engineering, and Vianney Koelman as chief scientist for petrophysics. Peak Well Services has appointed Nigel Avern as chief executive. Avern initially will base at the company’s two main offices – in Aberdeen, UK, and Perth, Australia. He will also sit on the company’s board of directors. Hyperdynamics Corp. has appointed Arthur F. Meadows as operations manager based in Conakry, Republic of Guinea. Polarcus has appointed Cameron Astill as VP of marketing, Asia-Pacific. He will be based in the company’s newly opened regional office in Singapore, and is responsible for managing and expanding the Polarcus brand presence across the region. UniversalPegasus International has appointed John Harrower as COO of its offshore division. With over 24 years experience in the engineering and construction industry, Harrower has served as senior VP of operations, as well as roles on senior project management teams with major energy and consulting firms. United Spiral Pipe has appointed Patrick J. Mullarkey as president. Paradigm Flow Solutions has appointed John Simpson as business development director and Martyn MacDonnell as business development manager. Drillsearch Energy has appointed Jean Moore as company secretary. Moore replaces Ian Bucknell who remains CFO.

Company news Petrofac is taking a 20% interest in Gateway Storage Co., the developer of a new subsea gas storage facility in the eastern Irish Sea off northwest England. Under the agreement, Petrofac will join Gateway as technical project operator, with joint responsibility for developing the project ahead of a final investment decision in 2011. Gateway says front-end engineering and design for the project is nearing completion and the focus now switches to project execution and finalization of the consortium of storage capacity holders and investors. The new 1.5 bcm (52.97 bcf) facility involves conversion of a subsea salt cavern. Assuming the project

comes onstream in 2016 as planned, it should add almost 30% to the current UK gas storage capacity. Oil Spill Response Ltd. says it has completed a response to a fuel oil spill in the Arabian Gulf. The spill, which occurred in early August in Kuwait, was the result of a malfunction in part of a process system. A small quantity of fuel oil spilled into the surrounding environment. Petrofac, the international oil and gas facilities service provider, will expand its capability to deliver Major Emergency Management (MEM) training to the US offshore and onshore oil and gas industry by opening a second, state-of-the-art simulation suite at its Houston Training Center. Freudenberg has agreed to acquire Offshore Seals (Asia) Pte Ltd., a manufacturer of specialized seals for the upstream oil and gas industry. The deal is expected to close on Jan. 3, 2011. Swire Oilfield Ser vices has launched a new subsidiary and has opened a regional office in Singapore. The Singapore office will work with the company’s existing European and Australian offices to target markets including Indonesia, China, Brunei, Malaysia, Thailand, Vietnam, and the Philippines. KBR is opening an Angola Operating Center in Luanda. The center will offer engineering, project management, and construction management services. Camcon Oil has signed a distribution partnership agreement with Amrtur Corp. Under the thee-year agreement, Amrtur will have the rights to sell, install, and support the APOLLO product range throughout the Sultanate of Brunei. Nakilat-Keppel Offshore & Marine (NKOM), Qatar’s newest offshore and marine shipyard, has been opened officially by the emir of Qatar and Singapore’s minister for Trade and Industry. This is a joint venture between Keppel Offshore & Marine and Qatar Gas Transport Co. Rosneft and China National Petroleum Corp. (CNPC) have agreed to expand cooperation in the upstream sector. The two companies signed a memorandum in St. Petersburg, Russia, under which they will consider purchasing new offshore and onshore blocks through LLC Vostok Energy. The latter is a joint venture owned 51% by Rosneft and 49% by CNPC, which was established to operate upstream assets in Russia. Energy XXI has bought certain shallow water Gulf of Mexico interests from ExxonMobil for $1.01 billion, the company reports. The properties include nine fields generally located between Energy XXI’s existing South Timbalier and Main Pass operations in water depths of 470 ft (143 m) or less. Shell Exploration and Production Co.

has awarded RBG a three-year contract to supply a coatings and maintenance program for offshore platforms in the Gulf of Mexico. RBG initially is commissioned to work on three of Shell’s six major offshore facilities in the Gulf of Mexico. The company will start work on one the platforms immediately. Audubon has launched a new SURF division led by Shamim Suleman. The new division will engineer, plan, design, and manage the construction of complete subsea systems, including flow assurance, heavy oil, riser systems, and pipeline and flow line ser vices. ConocoPhillips has awarded AMEC a contract for the detailed engineering and procurement for the Judy platform and the hook-up and commissioning of the new Jasmine facilities in the North Sea. Jasmine is a high-pressure/high-temperature gas-condensate reservoir discovered in June 2006. It is 9 km (6 mi) west of the Judy platform in ConocoPhillips’ J-block area. Jasmine will use the existing processing capacity on the Judy platform, with first production anticipated in 4Q 2012. Providence Resources has signed a 10-month option agreement with Star Energy Group concerning an exploration license offshore southeast Ireland. Providence currently has 100% ownership of Standard Exploration License (SEL) 1/07 (Dragon) in the St George’s Channel basin. The permit is in 90-m (295-ft) water depth, 40 km (25 mi) offshore. It contains the mapped extension of the Welsh offshore Dragon gas discovery into Irish waters, as well as the deeper Orpheus and Pegasus exploration prospects. Under the option agreement, Star can acquire a non-operated 50% interest in the license by conducting subsurface studies on the Dragon gas discovery. If it exercises this option, it will participate in drilling of a planned appraisal/development well. Baker Hughes has opened a new facility in Welshpool, Australia. The 340,000-sq ft (31,587 sq m) facility houses the company’s pumping, tubular, and process and pipeline services. The facility, which serves as the operations base for Australia and New Zealand, includes offices, laboratories, training space, workshop facilities, a warehouse and storage, and an equipment lay-down area. AGR Group has opened an office in Abu Dhabi. The facility will house AGR Petroleum Ser vices, AGR Drilling Ser vices, AGR Field Operations, and CannSeal. Schlumberger has inaugurated a new research and geoengineering center in Rio de Janeiro, Brazil. The Brazil Research and Geoengineering Center is designed to promote the integration of geosciences and engineering to improve hydrocarbon production and recovery from the complex



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BUSINESS BRIEFS

deepwater reservoirs and pre-salt carbonates offshore Brazil. Mainticare has agreed to represent Viking Moorings’ equipment and services throughout the western and central Mediterranean and in the Middle East. The company will also provide management, warehousing, and logistics services. Under a reciprocal arrangement, Mainticare will establish an office in Aberdeen to extend the services provided by Mainticare to UK clients operating offshore North Africa and in the Mediterranean. Oil Search has agreed to farm-in terms in two new exploration licenses offshore Papua New Guinea. PPL 276 is in the Gulf of Papua west of Pandora and Pasca gas fields. PPL 312 is in the northern Gulf of Papua, east of Uramu gas field. The farm-in arrangements are subject to ministerial approval. Oil Search says the acquisitions are in line with its strategy to optimize its license holdings with potential gas accumulations that could support commercialization. Special Oilfield Ser vices Co. (SOS) has signed a three-year agreement to sell, install, and support Camcon products throughout Oman.

China-based J&L Group, a technology and manufacturing leader in wire rope, synthetic rope, cable laid slings, and a variety of other rigging equipment for heavy lifting since 1985 announces the establishment of J&L Offshore, LLC headquartered in Houston. Harry Urech, a 30-year industry expert with extensive international oil and gas marketing and management credentials, heads J&L Offshore, LLC as its Executive Vice President. J&L Offshore will focus on offshore products currently produced as well as the enhancement of these products. Expansion of the company’s product line, with a focus on new equipment and services for the offshore oil industry, is also part of the J&L mission. Examples of new equipment being considered include traction winches, spooling machines, chain buoys, and anchors. J&L Offshore’s services may also include rig moving, as well as subsea installation and project engineering. Siemens Energy says it will supply a turnkey shoreside power supply system for the Goliat floating offshore platform for the production, storage and offloading of oil and gas north of Norway in the Barents Sea.

The Goliat platform will not, as is customary practice, be supplied with power generated by onboard gas turbines and generators but from the shore via a 106-km (66-mi) long subsea cable. This decision, in turn, is expected to result in a 50% reduction of CO2 emissions. Siemens says it will supply the shoreside power supply system, which essentially comprises a substation located in Hammerfest in northern Norway, overhead transmission lines, buried cable and a state-of-the-art reactive-power compensation system. The purchaser is the oil and gas company Eni Norge based in Stavanger, Norway. The shoreside power supply to the platform is scheduled to come on line in 2012; the start of production in the Goliat field is planned for late 2013. ABB says it has won several orders collectively worth $42 million to provide power supply infrastructure and equipment for several floating, production, storage and offloading (FPSO) vessels. The vessels will produce crude oil off the coast of Brazil; they will be operated by several oil and gas producers, with Petrobras as the end customer. The orders were booked during the third quarter.

Energy Industry Conference Proceedings Just because you missed the conference doesn’t mean you have to miss out on the information from the leading industry experts. PennEnergy Research now offers current and archived conference proceedings from PennWell energy-related events and conferences such as Deep Offshore Technology, Unconventional Gas International, and more. PennWell conferences and exhibitions bring together industry leaders to address the most relevant and important issues facing the energy industry today. It is information critical to how you do your job.

Don’t miss out on this valuable information just because you couldn’t make it to the conference this year. For more information: www.PennEnergy.com/index/conference.html


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C L A S S I F I E D A D V E RT I S I N G

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ADVERTISERS INDEX

SALES OFFICES PENNWELL PETROLEUM GROUP 1455 West Loop South, Suite 400, Houston, TX 77027 PHONE +1 713 621 9720 • FAX +1 713 963 6228 David Davis (Worldwide Sales Manager) [email protected] Bailey Simpson (Regional Sales Manager) [email protected] Glenda Harp (Classified Sales) [email protected] GREATER HOUSTON AREA, TX David Davis [email protected]

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Aker Solutions ...........................................13 www.akersolutions.com/subsea ARC Advisory Group - ARC World Industry Forum ..........................................47 www.arcweb.com/res/forumorl

National Oilwell Varco................................15 www.nov.com/rig National Oilwell Varco................................27 www.nov.com/totsubsea Newpark Drilling Fluids.. .............................9 www.newparkdf.com

B Baker Hughes, Incorporated .......................7 www.bakerhughes.com

C USA • CANADA Bailey Simpson [email protected] UNITED KINGDOM • SCANDINAVIA • THE NETHERLANDS 9 Tarragon Rd. Maidstone, Kent, United Kingdom ME16 OUR PHONE +44 1622 721222 • FAX +44 1622 721333 Roger Kingswell [email protected] FRANCE • BELGIUM • PORTUGAL • SPAIN • SOUTH SWITZERLAND • MONACO • NORTH AFRICA Prominter 8 allée des Hérons, 78400 Chatou, France PHONE +33 (0) 1 3071 1119 • FAX +33 (0) 1 3071 1119 Daniel Bernard [email protected] GERMANY • NORTH SWITZERLAND • AUSTRIA • EASTERN EUROPE • RUSSIA • FORMER SOVIET UNION • BALTIC • EURASIA Sicking Industrial Marketing, Kurt-Schumacher-Str. 16 59872 Freienohl, Germany PHONE +49 (0) 2903 3385 70 • FAX +49 (0) 2903 3385 82 Andreas Sicking [email protected]

Cameron ..................................................... 11 www.c-a-m.com Champions Pipe & Supply, Inc. ..................1 www.championspipe.com Clover Tool Company ................................51 www.clovertool.com Cortec Fluid Controls ................................39 www.uscortec.com

D Dril-Quip .................................................... C3 www.dril-quip.com

E Emerson Process Management .................3 EmersonProcess.com/IOonDemand

G Greater Lafourche Port Commission........37 www.portfourchon.com

O Offshore Mediterranean Conference .. .....19 www.omc.it Orr Safety Corporation .. ...........................33 www.orrsafety.com/kong

P PennWell Offshore Asia Conference & Exhibition ................................. 25, 91-102 www.offshoreasiaevent.com Offshore India Conference & Exhibition ..............................................24 www.offshoreoilindia.com Offshore West Africa Conference & Exhibition .................................. 49, 83-90 www.offshorewestafrica.com OGMTNA Conference & Exhibition ...103 www.ogmtna.com Petrosafe Offshore Conference ...........59 www.petrosafeoffshore.com PennEnergy Research ........................105 www.PennEnergy.com/index/conference.html

Subsea Tieback Forum & Exhibition ..............................................73 www.subseatiebackforum.com TOPSIDES, PLATFORMS, & HULLS Conference & Exhibition ......................53 www.topsidesevent.com Unconventional Oil & Gas India Conference & Exhibition ......................24 www.unconventionaloilandgas-india.com

ITALY SILVERA MEDIAREP Viale Monza, 24 - 20127 Milano, Italy PHONE +39 (02) 28 46716 • FAX +39 (02) 28 93849 Ferruccio Silvera [email protected] BRAZIL / SOUTH AMERICA Grupo Expetro/SMARTPETRO, Ave. Erasmo Braga 227, 11th floor Rio de Janeiro RJ 20024-900, BRAZIL PHONE +55 (21) 2533 5703 or +55 (21) 3084 5384 FAX +55 (21) 2533 4593 [email protected], Url [email protected] Marcia Fialho [email protected] JAPAN ICS Convention Design, Inc. 6F Chiyoda Bldg., 1-5-18 Sarugakucho Chiyoda-Ku, Tokyo 101-8449, Japan PHONE +81 3 3219 3641 • FAX +81 3 3219 3628 Manami Konishi [email protected] SINGAPORE 19 Tanglin Road #05-20 Tanglin Shopping Center Singapore 247909 PHONE +65 9616 8080 • FAX +65 6734 0655 Michael Yee [email protected] INDIA Interads Ltd., A-113, Shivalik, New Delhi 110 017 PHONE +91 11 628 3018 • FAX +91 11 622 8928 Rajan Sharma [email protected] NIGERIA/WEST AFRICA Flat 8, 3rd floor (Oluwatobi House) 71 Allen Ave, Ikeja, Lagos, Nigeria PHONE +234 805 687 2630 or +234 802 223 2864 Dele Olaoye [email protected]

H Halliburton..................................................21 Halliburton.com/smartwells Halliburton..................................................63 www.halliburton.com/hpht Hytorc....................................................43, 45 www.hytorc.com

R RigNet .........................................................16 www.rig.net

S J Jacobs Engineering Group, Inc. ...............38 www.jacobs.com

SBM Offshore .............................................31 www.sbmoffshore.com SMU-Cox School of Business ..................14 www.exed.cox.smu.edu/global

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KBR...... ...................................................... C4 offshore.kbr.com/os KOBELCO / Kobe Steel Ltd....... ................35 www.kobelcoedti.com www.kobelco.co.jp

Transocean........ ........................................ C2 www.deepwater.com

L LAGCOE......................................................55 www.LAGCOE.com

M Magnetrol International.. ...........................29 magnetrol.com McDermott.. ................................................23 www.mcdermott.com Mustang Engineering.. ..............................41 www.mustangeng.com

W Weatherford..............................................4, 5 weatherford.com Wison Floating Systems ...........................17 www.wisonfs.com World Petroleum Congress .......................57 www.20wpc.com The index of page numbers is provided as a service. The publisher does not assume any liability for error or omission.


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BEYOND THE HORIZON

Upping the ante for leadership accountability in oil and gas Oil and gas has always been a high stakes business. Oil and gas leaders are called upon continually to rally their lifetimes of experiences and knowledge to make quick decisions. In essence, these executives are stepping up to the table and placing their leadership bets. Decisions have to take into account the safety of people, the viability of the environment, and the future of the companies they lead. Increasingly in today’s business environment for oil and gas production, they also may be risking their own personal liability. As the stakes for management decisions grow, so do the demands for leadership accountability. Now more than ever, oil and gas leaders must cultivate a culture of broader accountability in which managers at all levels make operational decisions based on business acumen and a clear understanding of the firm’s goals, objectives, strategies, and values. Managers must feel confident in their understanding of the organization and have the proper support to make those decisions. It is timely for oil and gas leaders to review how to create a culture of accountability. High level executives must communicate company values and goals clearly throughout the corporate ranks and coach managers to align with top-level thinking and to push back when they see either adversity or opportunity looming. All employees are empowered to bring their best to the table in organizations with a culture that encourage trust and the courage to have candid conversations at all levels. While creating an environment of accountability starts with top executives, more and more firms in the oil and gas industry are served by Human Resources (HR) functions with knowledge and skill in proven models of leadership and organization development. They are able to aggressively get top executives involved at the level needed to build accountability. Oftentimes these HR pros turn outside the organization to find the additional expertise and resources to multiply their efforts. Industry associations and universities, for example, are ideally positioned to both lead and support cultural transformation. By their very definition, oil and gas associations are embedded in the industry at all levels. Unlike companies, these organizations see industry needs and priorities unclouded by competitive positioning. Many associations were founded to advance operational and technical excellence, but increasingly they are promoting managerial excellence as well. American Petroleum Institute (API), for example, has expanded its technical curriculum to offer oil and gas profes-

sionals access to skill-building in management and organizational development through the SMU Cox School of Business’ Executive Education program – a leader in providing management development and leadership skills building in oil and gas. Universities are uniquely positioned to provide research-based content that is tested and verified. And, as educators, universities are committed to building capability rather than dependency. In a true industry win-win, API and SMU Cox are working together to offer a suite of executive education programs to foster accountability among top and mid-level oil and gas leaders. Companies must rethink their approach to training in order to use a university effectively to support organization change. Rather than seeking academic subject matter experts and a traditional classroom model, companies can engage universities to work in deeper partnership to provide learning experiences that apply directly to current business challenges and that enable managers at all levels to try new behaviors and gain comfort with them through structured feedback and accountability. Behavior change that supports accountability is happening in the context of the impending “great crew change” -- the ushering in of the millennials as baby boomers retire. By 2012, all MBA students will be of the millennial generation. As oil and gas firms strive to be the employers of choice for this source of replacement talent, they can rely on the experience of their university partners for guidance and help. The blend of API’s deep industry presence coupled with SMU Cox’s industry-oriented expertise in management development, organization change, and intergenerational experience is helping meet the needs of the oil and gas industry in the more complex business environment of the coming decades. Through this new model, the industry can empower a generation of leaders to calculate and respond to risk in a whole new way and place their leadership bets with confidence.

John Modine

American Petroleum Institute Frank Lloyd

SMU Cox School of Business Executive Education

This page reflects viewpoints on the political, economic, cultural, technological, and environmental issues that shape the future of the petroleum industry. Offshore Magazine invites you to share your thoughts. Email your Beyond the Horizon manuscript to David Paganie at [email protected].

108 Offshore January 2011 • ___________ www.offshore-mag.com


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FOR

Since 1947, KBR has been at the leading edge of offshore design, engineering and construction. By bringing together the right people, the right planning and the right projects, we continue to build the infrastructure to get oil and gas resources to market … delivering successful solutions around the world.

Visit us at Booth #105 at the Topsides Conference & Exhibition February 1-3, 2011, Moody Gardens, Galveston, Texas

We Deliver

For more information, visit offshore.kbr.com/os or call (713) 753-4523 K10175 © 2011 KBR, All Rights Reserved


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