Offshore Magazine - February 2011

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February 2011

World Trends and Technology for Offshore Oil and Gas Operations

Asia-Pacific activity picks up

Rig market review 4D seismic advances Presidential spill report nt : e E ID lopm S IN deve ter s tic po c Ar Contents

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MqM q THE WORLD’S NEWSSTAND®

Are you stuck with mature fields producing up to 98% water, because workovers are just too expensive? Now FMC Technologies has the tool – thoroughly field-tested in the North Sea – to boost production using less expensive, monohull vessels. It’s called riserless light well intervention (RLWI), and it can increase oil recovery by up to 46% – at half the usual cost. Discover the full potential of our intervention technologies at www.fmctechnologies.com

We put you first. And keep you ahead. www.fmctechnologies.com © 2011 FMC Technologies. All rights reserved.


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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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© Copyright 2011 Aker Solutions. All rights reserved.


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Succeeding in subsea today takes

broader capabilities, bolder strategies, brighter ideas. E2E Subsea It stands for End-to-End Subsea. It means every part of your project performs. It means you’re in complete control.

Aker Solutions is the only company structured to help you succeed in every stage of your development and production field lifecycle. We do this through a purposeful integration of technology, service capability and regional expertise known as End-to-End Subsea. Subsea is a key component within Aker Solutions’ complete oilfield services offering, which delivers integrated solutions to take on your biggest challenges and the confidence of working with a single accountable source that backs its work. We can assist with the entire lifecycle of your field, or selected systems within it. You’re the one in control. Take a more enlightened approach to subsea.

www.akersolutions.com/subsea


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International Edition Volume 71, Number 2 February 2011 CONTENTS

Celebrating Over 50 Years of Trends, Tools, and Technology

DEEPWATER HORIZON AFTERMATH US Spill commission hands down recommendations.......... 34

Subsea gas hydrates offer huge deepwater energy potential ...... 76 Research results over the past decade, including drilling and coring, experimental studies, and numerical simulations, are clarifying the resource potential of gas hydrates.

Presidential panel calls for changes to Gulf of Mexico drilling and production regulations.

RIG MARKET REVIEW Reviewing the world offshore rig market ............................ 36 The worldwide offshore rig market continues to suffer from oversupply as new rig deliveries outstrip demand. As new rigs built to everhigher specifications are delivered, older rigs have more trouble securing contracts.

46

Over the past decade, the industry has had great success pushing into the deepwater frontier through innovation. However, this success has come with a price.

ASIA-PACIFIC/AUSTRALIA Transportation, installation techniques evolving for heavier topside consignments ........................ 46 Industry veteran reflects on experiences and lessons learned over nearly 30 years in the offshore oil and gas market.

India looks to develop offshore resources ............................ 52 India is expecting $2 billion in fresh investments to be made over the next eight years in new exploration under the New Exploration Licensing Policy (NELP) IX program, which offers 34 blocks spread over 88,800 sq km (34,286 sq mi), 65% of which is virgin acreage.

Offshore Asia heads to Singapore March 29-31.................. 56 The annual Offshore Asia Conference & Exhibition heads to Singapore’s new Marina Bay Sands Resort on March 29-31 expecting to expand on its success in 2010.

ARCTIC Technology evolves for Arctic development ...................... 62 Multiple offshore Arctic fields have been developed over the preceding three decades but there still is relatively little oil and gas being produced from the reportedly large estimated in-place reserves.

ENGINEERING, CONSTRUCTION, & INSTALLATION Meeting the challenge of deepwater development ................ 80

PRODUCTION OPERATIONS P&A innovations increase efficiency, safety ................................. 84

70 Assessing the state of arctic technology development ................... 66 Sooner or later, petroleum development of the Arctic Circle will take place. The technology exists today to safely and reliably develop the 25% of world oil and gas untapped reserves that exist there.

SSTB PREVIEW Subsea Tieback Forum returns to San Antonio ....................... 70 The annual Subsea Tieback Forum & Exhibition returns to San Antonio Feb. 22-24, 2011, at the Henry B. Gonzales Convention Center. More than 3,000 attendees and 150 exhibitors are expected at this year’s conference.

GEOLOGY & GEOPHYSICS Atlantis project proves viability of OBN in 4D .......................... 72 The world’s first ocean bottom seismic nodeon-node time-lapse (4D) monitor survey was acquired in 2009 at the Atlantis field in the Gulf of Mexico. Field operations went as planned safely and the equipment worked as expected.

Plug and abandonment operations face a long list of challenges, including rising costs, safety concerns, environmental issues, and rapidly growing demand. Conventional methods and tools are frequently unable to address these concerns.

Post-hurricane decommissioning poses unique challenges .................... 90 The offshore oil and gas industry in the Gulf of Mexico is susceptible to natural and manmade disasters. From 2004-2008, five major hurricanes (Ivan, Katrina, Rita, Gustav, Ike) destroyed 180 structures and 1,070 wells

Gas-lift valve design addresses long-term well integrity needs .......... 98 Many major operating companies are looking to eliminate the well integrity compromises that have previously existed in their gas lift well designs.

Demand for emergency management training on the rise..... 100 Imagine having the opportunity to role play emergency response efforts, to simulate in a controlled, monitored environment the experience of a helicopter crash, but without the actual disaster. That is exactly what Major Emergency Management (MEM) training is designed to do.

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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𰀻𰁞𰁣𰁙𰁞𰁣𰁜𰀕𰁤𰁞𰁡𰀕𰁢𰁚𰁖𰁣𰁨𰀕𰁜𰁤𰁞𰁣𰁜𰀕𰁙𰁚𰁚𰁥𰁚𰁧𰀣𰀕𰁉𰁝𰁖𰁩𰀕𰁢𰁚𰁖𰁣𰁨𰀕𰁧𰁞𰁨𰁠𰀣𰀾𰀕𰁣𰁚𰁚𰁙𰀕𰁧𰁚𰁖𰁡𰀢𰁩𰁞𰁢𰁚𰀕𰁧𰁚𰁨𰁥𰁤𰁣𰁨𰁚𰀕𰁛𰁤𰁧𰀕𰁧𰁚𰁡𰁞𰁖𰁗𰁡𰁚𰀕𰁥𰁧𰁤𰁙𰁪𰁘𰁩𰁞𰁤𰁣𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰀕𰁬𰁞𰁩𰁝𰀕𰁡𰁚𰁨𰁨𰀕𰁚𰁭𰁥𰁤𰁨𰁪𰁧𰁚𰀕𰁛𰁤𰁧𰀕𰁢𰁮𰀕𰁥𰁚𰁤𰁥𰁡𰁚𰀣

Get reliable offshore production control and monitoring from the safety of onshore. You can now draw on the combined expertise of your best and brightest personnel by centralizing them to oversee multiple production units. New predictive intelligence in offshore assets gives them advanced warning of changing conditions to your process and the health of your equipment, with time to correct as if they were there. And maintenance procedures become more responsive, saving you time and money while minimizing the risk of equipment failure. All to provide greater control over your operations even as you lower the risks — to the environment, to your operations and to your people. It’s time to bring them home. Learn more at EmersonProcess.com/Deepwater

𰁉𰁝𰁚𰀕𰀺𰁢𰁚𰁧𰁨𰁤𰁣𰀕𰁡𰁤𰁜𰁤𰀕𰁞𰁨𰀕𰁖𰀕𰁩𰁧𰁖𰁙𰁚𰁢𰁖𰁧𰁠𰀕𰁖𰁣𰁙𰀕𰁖𰀕𰁨𰁚𰁧𰁫𰁞𰁘𰁚𰀕𰁢𰁖𰁧𰁠𰀕𰁤𰁛𰀕𰀺𰁢𰁚𰁧𰁨𰁤𰁣𰀕𰀺𰁡𰁚𰁘𰁩𰁧𰁞𰁘𰀕𰀸𰁤𰀣𰀕𰂝𰀕𰀧𰀥𰀦𰀦𰀕𰀺𰁢𰁚𰁧𰁨𰁤𰁣𰀕𰀺𰁡𰁚𰁘𰁩𰁧𰁞𰁘𰀕𰀸𰁤𰀣


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International Edition Volume 71, Number 2 February 2011

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COVER: Exploration and production activities are picking up in the Asia-Pacific region, as evidenced by Chevron’s $3.1-billion Platong II project in the Gulf of Thailand. First production is expected later this year. Photo courtesy Chevron.

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SUBSEA Meeting the challenges of subsea boosting ........................................................... 102 The addition of subsea booster pumping to a development increases the complexity of the safety system integration task over that of conventional subsea field developments. More conventional developments typically only deal with a subsea production control system and a topsides process control system.

FLOWLINES AND PIPELINES Radioisotope technology helps insure pipeline flow .............................................. 104 The growing demand for fossil fuels means an increasing number of subsea pipelines to transport the oil and gas. This, in turn, has led to the application of various radioisotope technologies to help offshore operators achieve effective pipeline flow assurance.

108

Online monitoring enhances flow assurance .................. 108 New oil and gas field developments are getting more advanced and often include subsea installations, satellite wells, or subsea-to-beach solutions. Long multi-phase lines, tie-ins, subsea-tobeach, and subsea production and processing can pose different operational challenges.

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Online .................................................... 8 Comment ............................................. 10 Data ..................................................... 12 Global E&P .......................................... 14 Offshore Europe .................................. 20 Gulf of Mexico ..................................... 22 Subsea Systems ................................. 24

Vessels, Rigs, & Surface Systems ...... 26 Drilling & Production .......................... 28 Geosciences ........................................ 30 Offshore Automation Solutions ......... 32 Business Briefs ................................. 118 Advertisers’ Index............................. 123 Beyond the Horizon .......................... 124

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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

Available at

VICE PRESIDENT and GROUP PUBLISHER Mark Peters [email protected]

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TECHNOLOGY EDITOR, SUBSEA & SEISMIC

Eldon R. Ball [email protected]

Gene Kliewer [email protected]

EDITOR-EUROPE

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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) 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]

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

AUDIENCE DEVELOPMENT MANAGER

Offshore-mag.com Upcoming webcasts ➤ Meeting the Challenges of Arctic Development

Feb. 24, 2011: Arctic oil and gas resources represent the next big chapterr 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. The third speaker will be Joe Gagliardi, Arctic Solutions and Technology Director, ION Geophysical Corp., and he will discuss the challenges of acquiring and processing seismic data in Arctic environments.

➤ Reviewing offshore safety systems and automation integrity Rajan Batra, Electrical, Instrumentation & Control Lead for Major Capital Projects, Chevron International Exploration & Production division, will discusss the latest developments and trends in offshore safety systems and automation integrity. Other speakers to be announced soon.

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

On demand ➤ Building an Emergency Spill Response System

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.

➤ 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 – and the winners were announced in a webcast on Dec. 7, and in the December issue. The projects are selected on the basis on best use of innovation in production method, application 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 ____________________

Publications Mail Agreement Number 40052420 GST No. 126813153

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


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COATINGS We coat with the best to protect from the worst. In the past five years alone, Bredero Shaw has successfully launched 10 new technologies in response to the most extreme conditions in the rapidly changing oil and gas industry. Our complete portfolio includes over 240 active patents and 40 industry-leading technologies to provide you with value added products and services. All the way from the lab to the field, our efforts are grounded in real client needs. Whether your pipeline is in the harshest desert or the deepest sea, our innovations will keep it protected and productive. And, with the largest team of R&D and technical professionals in the industry, we’ll continue doing just that. Bredero Shaw. the GLOBAL LEADER in pipe coating solutions.

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ENGINEERING PLASTIC SOLUTIONS

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COMMENT

David Paganie • Houston

India licensing round offers new acreage, terms India is expecting $2 billion in new investments to be made over the next eight years under the New Exploration Licensing Policy (NELP) IX program, which offers 34 blocks spread over 88,800 sq km (34,286 sq mi), 65% of which are available for the first time. On offer are eight deepwater blocks, seven shallow water blocks, and 19 onshore blocks. Foreign participation has been minimal in the exploration and development of India’s offshore resources due, primarily, to the regulatory environment. Officials, however, assure that it has taken into consideration concerns expressed by E&P companies, in the preparation of the bid documents for the recent licensing round. Addressing the NELP IX road show in Singapore, India’s petroleum and natural gas minister Murli Deora assured investors of a level playing field, dismissing suggestion of any favor towards the country’s public or private sector companies, reported Contributing Editor Gurdip Singh. “Invest in Indian E&P and become partners in our progress and our efforts to enhance the energy security of the country,” said Deora, who headed a high-level delegation seeking E&P participation as well as investors from Singaporebased financial institutions. Singh’s full report from the roadshow stop in Singpaore begins on page 52. Since its inception in 1997-98, NELP has secured about $15.6 billion in E&P investment, resulting in 87 oil and gas discoveries in a total of 26 blocks with reserves of more than 640 million metric tons of oil equivalent. Although the Indian government views NELP as a success, its intention is to move to the Open Acreage Licensing policy (OALP) regime in the near future. Under this policy, officials say companies can choose any block for offer at any time, without waiting for the regular bid rounds under NELP. The blocks will be awarded to the party giving the best bid at any time of the year, officials say. To implement this policy, the Directorate General of Hydrocarbons is creating a National Data Repository. To address India E&P policy, technical issues, among other topics, PennWell is holding its inaugural Offshore India and Unconventional Oil & Gas India conference & exhibition in Mumbai, India, Sept. 14-16, 2011. As co-chair of the conference, I invite you to submit an abstract for the event. To be considered for a technical session, please submit your 100-400 word abstract by Feb. 18. Submission guidelines are available at www.offshoreoilindia.com/index/conference____________________________ information.html. __________

Rig market review

Nylacast Ltd (UK) t: 0044 (0) 116 276 8558 f: 0044 (0) 116 274 1954 e: [email protected] w: www.nylacast.com

Nylacast LLC (USA)

At the time of this writing, industry had ordered about 10 floaters and 20 jackup rigs since 4Q 2010. This compares to having ordered only 5 floaters and 6 jackups over the preceding 12 months. Most of these assets are being built on spec, as drillers look to capitalize on favorable shipyard pricing. However, the worldwide rig market continues to suffer from oversupply as new rig deliveries outstrip demand, according to Mathew Donovan, marine market analyst, ODS-Petrodata. About 104 mobile offshore drilling rigs are under construction or on order around the world, with 57 of these rigs scheduled for delivery this year. Only 30 of the rigs set for delivery this year have contracts lined up. Donovan’s global rig market review and analysis begins on page 36.

Subsea Tieback Forum & Exhibition The annual Subsea Tieback Forum & Exhibition returns to San Antonio Feb. 22-24, 2011, at the Henry B. Gonzales Convention Center. More than 3,000 attendees and 150 exhibitors are expected at this year’s conference. You can learn more about the event in the preview on page 70. We look forward to seeing you there!

t: 001 717 2705600 f: 001 717 2709760 e: [email protected] w: www.nylacastusa.com

Nylacast South Africa (PTY) t: 00 2711 3977077 f: 00 2711 3977017 e: [email protected] w: www.nylacast.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

Jan 2009 – Dec 2010 Total fleet

Contracted

850

100%

750

90%

650

80%

550

70%

450

60%

350 Jan 09 Apr 09 July 09 Oct 09 Jan 10 Apr 10 July 10 Oct 10

50%

Copyright © 2011 ODS-Petrodata Inc.

GoM drilling permits issued 100 90

Drilling permits

80 70 60 50 40 30 20

21

18

15

14

July

Aug.

Sept.

9

10 0

June

Oct.

13

15

Nov.

Dec.

Average

Maximum

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

$387,510 $388,416 $389,265 $393,652 $386,397 $391,011 $398,169 $398,037 $403,350 $412,682 $404,371 $409,976

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

$28,000 $28,000 $28,000 $28,000 $28,000 $27,000 $25,000 $6,500 $10,000 $10,000 $10,000 $30,000

$129,531 $127,233 $123,335 $118,905 $116,205 $115,315 $115,693 $115,249 $114,822 $112,539 $111,092 $110,332

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

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

$368,963 $363,623 $365,389 $362,077 $360,359 $357,489 $351,888 $355,320 $355,826 $357,311 $359,805 $362,365

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

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

Working

Fleet utilization rate

No. of rigs

Contracted fleet utilization

Minimum

Source: Rigzone.com

Source: BOEMRE

Asia-Pacific rig utilization

Worldwide rig utilization

120

100 90

100

80 70 Percent

60

50 40 30 10

1 ar 0 ch 1 Ap 0 ril 1 M 0 ay 1 Ju 0 ne 10 Ju ly 10 Au g 1 Se 0 pt 10 O ct 10 No v 10 De c 10

10

M

Fe b

09

0 c

1 M ar 0 ch 1 Ap 0 ril 1 M 0 ay 1 Ju 0 ne 10 Ju ly 10 Au g 1 Se 0 pt 10 O ct 10 No v 10 De c 10

10

Fe b

c

Ja n

09

0

Drillships Semisub Jackups

20

Ja n

20

Source: Rigzone.com

Drillships Semisub Jackups

De

Source: Rigzone.com

40

60

De

Percent

80



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GLOBAL E&P

Jeremy Beckman • London

North America Cairn Energy has contracted two deepwater DP rigs for a four-well exploration program this year offshore Greenland. The semisubmersible Leiv Eiriksson and the drillship Ocean Rig Corcovado will drill the wells. Cairn’s initial campaign last year delivered one sub-commercial gas discovery.

South America Repsol is teaming up with Ecopetrol and Petrobras to explore the Tayrona block in the Colombian sector of the Caribbean Sea. Tayrona covers a total area of over 1.6 million ha (6,400 sq mi). ••• Petrobras has filed a declaration of commerciality to Brazil’s National Agency of Petroleum for its light oil and gas discoveries in block BM-S-11 in the Santos basin. Under its evaluation and development plans, Petrobras proposes re-naming the Tupi and Iracema fields Lula and Cernamba. Minas Gerais

Rio de Janeiro

Tevol

field in 2013, involving well tiebacks to the FPSO Cicade de Sao Paulo. ••• In the Campos basin, the P-57 FPSO has begun producing oil ahead of schedule on Petrobras’ Jubarte field. SBM Offshore managed construction of the vessel in yards in Singapore and Brazil, and will operate it during Jubarte’s first three years of production. The field is 80 km (49.7 mi) off the Espirito Santo coast in a water depth of 1,260 m (4,134 ft). P-57 can process 180,000 b/d of oil and 2 MMcf/d of gas, to be supplied via 15 producer and seven injector wells. ••• Maersk Oil is acquiring SK do Brasil for $2.4 billion. The latter’s assets include stakes in three blocks in the Campos basin containing the producing Polvo oil field and the Wahoo and Itaipu discoveries. Maersk says Wahoo and Itaipu will be appraised later this year, and further prospects in the blocks could be drilled in 2013.

Reduc

Map shows location of the newly named Lula and Cernamba fields in Brazil’s Santos Basin.

Revap

São Paulo

Terig

Rio de Janeiro

São Paulo Recap RPRC

Tebar

Oliva Atlanta

Mexilhão

Gasoduto de Merluza

Uruguá

Ilha Bela

T T

Carapiá Tambuatá

Lagosta

Cernambi

Merluza

T

T

Guaiamá Piracucá

The semisubmersible Maersk Deliverer drilled the Cormoran-1 well in block 7, a short distance south of the 2003 Pelican-1 discovery, in 1,630 m (5,348 ft) of water. It encountered four separate gas columns, one of which flowed 22-24 MMcf/d during a test constrained to avoid sand production. The rig later transferred 22 km (13.7 mi) southwest to drill the Gharabi-1 exploratory well for PC Mauritania. ••• Tullow Oil has proven further commercial quantities of gas/condensate in the Tweneboa structure in Ghana’s Deepwater Tano license. The drillship Deepwater Millennium drilled Tweneboa-3 at a location 12 km (7.5 mi) southeast of the discovery well in 1,601 m (5,252 ft) of water. Two deviated boreholes were incorporated to test separate areas of the field, with the sidetrack into the Ntomme anomaly delivering 34 m (111 ft) of net pay in stacked reservoir sandstones. Next up for the drillship is the tophole section of Tweneboa-4, followed by Enyenra-2A, designed to appraise the potential down-dip of last year’s Owo-1 oil discovery. Tullow is working on development options for the Greater Tweneboa area. ••• Noble Energy has approval from Equatorial Guinea’s government to proceed with development of the Alen gas/condensate field, formerly known as Belinda. Most of Alen’s reservoir is in offshore block O, the remainder extending into the northern part of Block 1. The initial development plan calls for three producer and three subsea gas injector wells tied into a processing platform. Produced condensate will be separated and transported via a pipeline to Noble’s Aseng FPSO, 15 mi (24 km) to the south on block 1, with the gas being re-injected into Alen’s reservoir to boost liquids recovery.

Lula

North Africa Campos De HC

The company and its partners have also chartered two further FPSOs, each with capacity to handle production of 150,000 b/d of oil and 212 MMcf/d of gas. One will be deployed on the southern part of Cernamba, with the other despatched to the Guara Norte area in Santos basin block BM-S-9. Both should be ready for start-up in 2014. This brings the total of FPSOs on order for both blocks to 13. At Guara, an extended well test started in late December, using the FPSO Dynamic Producer. The test is due to last for five months, producing around 14,000 b/d of oil. Another pilot production scheme is scheduled for the

••• Desire Petroleum has terminated its latest exploration well in the offshore North Falklands basin, after encountering only gas shows in the Dawn/Jacinta structure. The semisubmersible Ocean Guardian has since reverted to Rockhopper, which drilled the region’s sole commercial discovery last year, named Sea Lion. Desire has one further slot for the rig, at a yet to be determined location.

West Africa Dana Petroleum has notched its second deepwater gas find offshore Mauritania.

Sonde Resources says its Zarat North-1 appraisal well offshore Tunisia exceeded expectations. Three production tests flowed quantities of gas and condensate, and the thickness of the hydrocarbon column was twice the original prognosis. The well was drilled in the 7th of November block, close to Marathon’s two Zarat discovery wells, with hydrocarbons encountered at the same structural levels. Sonde plans development studies, with options including use of horizontal wells. PA Resources, which has an operating interest in part of Zarat, south of Sonde’s blocks, is developing another Tunisian offshore find, Didon North, 5 km (3.1 mi) northeast of the Didon field production platform. Didon North should produce first oil later this year.



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GLOBAL E&P

Russia/Caspian Sea BP and Rosneft have committed to jointly explore and develop three blocks in the South Kara Sea offshore northern Russia. Rosneft was awarded the licenses for blocks EPNZ1, 2, and 3 in 2010. BP says this is a highly prospective area, equivalent in size to the UK North Sea. The two companies first teamed in 1998 to perform exploration offshore Sakhalin Island. Under the new agreement, they will establish an Arctic Technol-

ogy center in Russia, which will develop technologies and safe practice for extraction of resources from the Arctic shelf. ••• In the Azeri sector of the Caspian Sea, BP has contracted KCA Deutag to manage all its platform drilling facilities over a five-year period, with options for a further five years. The agreement takes in six platforms on the Azeri-Chirag-Gunashli and Shah Deniz fields. KCA owns the rig on the Chirag facility,

which it leases to BP, and is also involved in detail design of the next platform rig for the Chirag Oil project, due to be installed in 2013. •••

ACE provided winches to help lift a platform for Petronas in the Turkmen sector of the Caspian, pictured here at a local quayside.

Dragon Oil has been installing three new in-field pipelines between platforms on its Cheleken Contract Area (CCA) fields in the Turkmen sector. These are designed to eliminate network bottlenecks by increasing throughput capacity. The company has also put in place a new 40-km (24.8-mi), 30-in. trunkline between block II and the CCA Central Processing Facility, where capacity has been doubled to handle up to 100,000 b/d of liquids and up to 220 MMcf/d of gas. Also in the Turkmen sector, Petronas/MMHE have installed a topsides and jacket for a new platform. ACE Winches in Aberdeen supplied 20 winch packages for the lifting program.

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Eastern Mediterranean/ Middle East Noble Energy has confirmed that its latest deepwater well in the Levantine basin offshore Israel is a potentially major gas discovery. The well on the Leviathan structure, in the Rachel license, intersected a minimum of 220 ft (67 m) of net pay in numerous subsalt Miocene intervals. These appear to be geologically similar to those encountered in the Tamar field 29 mi (47 km) to the northeast. Leviathan-1, drilled 80 mi (130 km) offshore Haifa, in 5,400 ft (1,645 m) water depth, continues to be deepened to evaluate two further intervals. ••• Infield Systems sees Israel providing just over $2 billion in capex commitments for offshore projects over the next five years. However, according to the analysts’ new Middle East & Caspian Sea Oil & Gas Market Report to 2015, Iran and Saudi Arabia will remain the major offshore players in the Middle East region. The report foresees offshore capex across the Middle East and Caspian sectors over the next five years totalling around $39.9 billion, a 33% increase over the outlay during 2006-10. Spending on Iranian offshore projects could

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GLOBAL E&P

double to around $12 billion, with capex for projects off Saudi Arabia totalling $5.8 billion during 2011-15, up from $4.5 billion in 200610. Gas demand throughout the region will be one of the main drivers of this growth. ••• Iran’s Ministry of Petroleum plans to drill 1,700 offshore wells over a five-year period ending in 2015. These and onshore drilling activity will incur a total cost of $40 billion. “Moving towards expanding horizontal drill-

ing and using its related technologies are among the oil industry priorities,” an official told the Iranian news service Shana. ••• RasGas Co., the joint venture between Qatar Petroleum and ExxonMobil, has contracted Hyundai Heavy Industries to supply offshore facilities for the Barzan Gas project. Hyundai’s scope, valued at $900 million, includes supply and installation of three wellhead platforms, 200 km (124 mi)

TETRA

of subsea pipelines and 100 km (62 mi) of subsea cables by end-2013. Barzan, 80 km (49.7 mi) northeast of Ras Laffan Industrial City, will deliver 1.9 MMcf/d of gas, and is due onstream in 2014.

India Norwegian company Rocksource has requested an extension from India’s government to the Phase I period for exploration block CY-DWN-2001/1 in the Cauvery Basin, offshore southeast India. The PSC terms required three exploratory wells – two have been drilled, both of which were dry, although neither tested the primary prospect. The third well is due to spud before midMarch, by which point Petrobras may have farmed into 25% of the block.

Asia-Pacific BG Group has discovered gas with the first deepwater well drilled in China’s Qiongdongnan Basin. Lingshui 21-1-1 was drilled on block 64/11, 130 km (81 m) offshore in a water depth of 1,338 m (4,390 ft). BG plans further analysis to evaluate potential elsewhere in the block. ••• Coastal Energy has discovered two new accumulations in its Songkhla area in the Gulf of Thailand, which it has named Songhkla North and Songkhla East. The wells in both cases were targeting pay at Lower Oligocene and Eocene levels. Coastal next plans to drill potentially high-impact targets at Bua Ban North. ••• Repsol Exploration is farming into the East Bula and Seram production-sharing contracts offshore Indonesia operated by Niko Resources. Niko has acquired 2D and 3D seismic over the license area. The two companies were already partners on Indonesia’s Cendrawashi Bay 11, 111, and 1V permits.

Australasia

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GDF Suez has contracted Granherne for an upstream pre-FEED study for the Bonaparte LNG project in the Bonaparte basin offshore Australia’s Northern Territory. The project, which GDF Suez is developing with Santos, involves a proposed floating offshore liquefaction plant capable of producing 2 MM metric tons/yr (2.2 MM tons/yr). Granherne is providing subsea engineering, field development planning, process, and flow assurance studies from its offices in Perth. ••• Apache has started decommissioning operations at its Legendre oil field, 90 mi (150 km) off the north-west coast of Western Australia. Facilities to be removed include the mobile offshore production unit Ocean Legend, the floating storage and offloading tanker Karratha Spirit, and subsea equipment. 

tetratec.com Previous Page | Contents | Zoom in | Zoom out | Front Cover | Search Issue | Next Page

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OFFSHORE EUROPE

Jeremy Beckman • London

Development brings Norway short-term gains Upstream investment on the Norwegian shelf could reach a new peak this year of NOK 150 billion ($25.6 billion), according to the Norwegian Petroleum Directorate (NPD). The forecast increase (up from NOK 130 billion, or $22.2 billion, in 2010) is due largely to major new projects swinging into action, such as Statoil’s Gudrun and Valemon in the North Sea. But NPD also sees worrying indicators, with discoveries failing to offset falling production. Over the short term, the outlook remains healthy, with investments set to continue climbing through 2013. This year, NPD expects more development plans to be submitted, headed by ConocoPhillips’ proposals for Ekofisk Sor and Eldfisk II in the southern North Sea. Both will feature new production platforms. Others in line for platforms Lundin 11%

Talisman 9%

Shell 6%

BG 4%

Centrica 4% Wintershall 4% RWE Dea 4%

Statoil 21%

Nexen% ExxonMobil 2% BP 2% ConocoPhillips 2% Total 2% Petro-Canada 2%

Det norske 11%

Eni 2% Charts shows wells drilled by operators on the Norwegian shelf during 2010 (Source: Norwegian Petroleum Directorate).

are Total’s Hild oil field, following a successful delineation well last year, and Lundin’s Luno and Det norske oljeselskap’s Draupne, which could be developed jointly. Last month, BG put forward plans to produce its smaller Jordbaer discovery via a chartered FPSO, and could do the same later this year for its Bream field in the North Sea. During 2010, Norwegian operators completed 41 exploration and appraisal wells, NPD says, of which 16 were discoveries. Most were small-mid-size finds close to production complexes in the North Sea and Norwegian Sea, with only one wildcat in the Barents Sea. The most active drillers were Statoil and Det Norske (nine wells each). This year NPD anticipates 50-55 exploratory well spuds across the shelf. The major disappointment in 2010 was Norske Shell’s appraisal of the Gro gas discovery in the deepwater Norwegian Sea, and its dry hole on the Dalsnuten prospect in the same sector. These results, coupled with new surveys of unexplored offshore regions farther north, caused NPD to cut its estimate of Norway’s undiscovered resources from 3.3 to 2.6 bcmoe. Last year, Norwegian fields delivered 229.5 MMcmoe of production, 4% down on the figure for 2009, and NPD foresees further steady decline through 2015. Director Bente Nyland called for new measures to halt the downward drift, including increased development of mature fields.

Snohvit could provide further LNG feedstock Statoil and its partners in the Snohvit license in the Barents Sea may build a second train at the Hammerfest LNG plant on Melkoya Island. Expanding capacity could accelerate production of gas in the area and of reserves yet to be discovered. This would trigger further offshore development, including new production wells, subsea templates, and a second gas export pipeline. Feasibility studies are under way, but the new plant is unlikely to come onstream before 2018. The existing facilities handle supplies from the Snohvit field, which are sent to Melkoya via a 143-km (89-

mi) subsea pipeline. Currently, Train 1 produces 13,000 t/d of LNG, 900 t/d of LPG and 2,000 t/d of condensate.

UK to toughen offshore inspections Industry Association Oil & Gas UK welcomed the decision by Britain’s government to reject a moratorium on drilling in UK waters, following investigations into the Deepwater Horizon/Macondo oil spill. Chief Executive Malcolm Webb said any suspension of activity would be unnecessary and would undermine the UK’s energy security. The government’s Energy and Climate Change Committee, in its report into UK deepwater drilling, concluded that Britain’s regulatory regime was stricter than its counterpart in the US Gulf of Mexico. However, the authors did issue recommendations and observations that Oil & Gas UK did not agree with, notably the need for two sets of blind shear rams on BOPs, and a perceived lack of clarity concerning liability for offshore incidents. However, the government has decided to step up its program of inspections on UK offshore installations. It will recruit more specialist staff to implement 150 annual environmental inspections taking in all manned, fixed installations and around 24 drilling rigs. And it will allocate two inspectors instead of the present one for installations involved in deepwater or complex offshore programs. The requirement for increased inspections was first proposed last September by US Secretary of the Interior Ken Salazar, and later included in last month’s report by the US National Commission on Macondo. The UK government said it would review Britain’s oil and gas offshore regulatory regime in the light of the US investigations. This work will be undertaken by the Department of Energy and Climate Change, the Health & Safety Executive, and the Marine Coast Guard Agency, and will take into account the full life cycle of an offshore development.

UK drilling levelling off Deloitte’s Petroleum Services Group in Aberdeen counted 71 exploratory and appraisal well spuds on the UK shelf last year. Although this represented a drop of 9% on 2009, the total was consistent with levels seen during most of the past decade, according to energy partner Graham Hollis. Deloitte says well numbers may rise in 2011 if oil prices stay high, making more technically challenging drilling projects viable. This year, there have already been two confirmed discoveries. West of Shetland, Total proved gas in the Edradour prospect, close to its emerging Laggan-Tormore gas/condensate export facilities. In the Central North Sea, EnCore found oil in the Varadero structure, near last year’s Catcher discovery. Farther north, Xcite Energy suspended its 9/3b-6z horizontal appraisal well on the Bentley heavy oil field, following a successful flow test. The well will be available for re-use in a full field development.

PAR gains German foothold Swedish company PA Resources (PAR) has been awarded an exploration license offshore Schleswig-Holstein in northern Germany. The B20008-73 concession is adjacent to PAR’s Danish North Sea license 12/06, where two wells will be drilled later in the year, with similar objectives to prospect targets in the German permit. Among other leasing developments in Western Europe, Faroe Petroleum has agreed to acquire Nexen’s 28% stake in the undeveloped Perth oil field, 185 km (115 mi) northeast of Aberdeen in block 15/21c. Faroe is working with new operator Deo Petroleum to address technical challenges of the development, which could be tied back to nearby Tartan or Scott platforms. In the Rockall basin off Western Ireland, OMV has agreed to offload its 50% interest in License 3/05 to San Leon Energy for $5 million. The acreage includes the Killala and Kingfisher prospects. Assuming the transaction is approved, San Leon will seek to bring in other farm-in partners to this and its other licenses in the Irish Atlantic margin. 



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GULF OF MEXICO

Macondo commission releases report The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling investigation report was released to the public on Jan. 11, and some industry vendors are challenging its findings. While Halliburton says it continues to examine the report, it does disagree with some of the findings it has seen. In short, the report made the following conclusions: • The event could have been prevented. • Deepwater exploration and production have risks for which neither the government nor industry is prepared. • Fundamental reform is needed to assure human safety and environmental protection. Regulatory oversight of leasing, energy exploration, and production needs reform in both structure and decision making. • Technology, laws and regulations, and practices for containing, responding to, and cleaning up spills lags behind the risk of deepwater drilling. Government must close the gap and industry must support rather than resist the effort. • Scientific understanding of environmental conditions in sensitive environments is inadequate. A complete version of the report is available at _________ http://www.oilspillcommission.gov/. _____________ Halliburton’s initial disagreement is in regard to comments about the foam stability tests related to the cement pumped on the well. In general, Halliburton says, the commission selectively omitted information it provided concerning the amount of time required for the foam stability test to be completed.

Some deepwater drilling might move ahead The Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) says projects interrupted by the deepwater drilling moratorium in the Gulf of Mexico following the BP oil spill deserve special consideration in the approvals process. The Wall Street Journal reports that the Obama administration says it would clear a path for the 13 companies with wells already approved and under way when the moratorium took effect. These 16 sites still will have to meet the new environmental review criteria prior to approval. This new move would not affect permit requests pending when the moratorium hit and those submitted since. The continuing questions of what the criteria are and when any required federal inspections of the plans and/or equipment to be used might take place are not addressed in this new move.

Bruce Beaubouef • Houston

Helix inks agreements for Deepwater Containment System Helix Energy Solutions Group, Inc. has executed agreements for its Helix Fast Response System (HFRS) to be named as a spill response resource for the U.S. Gulf of Mexico in response plans submitted by oil and gas producers with state and federal authorities. The HFRS centers on two vessels, the Helix Producer I and the Q4000, both of which played a key role in the BP Macondo spill response and are presently operating in the GoM. Helix signed an agreement with Clean Gulf Associates (CGA), a non-profit industry group, making the HFRS available for a two-year term to CGA participants in the event of a GoM well blow out incident in exchange for a retainer fee. In addition to the agreement with CGA, Helix also has signed separate utilization agreements with 19 CGA participant member companies to date specifying the day rates to be charged should the solution be deployed. “We are pleased to have reached agreements with a key group of industry players to provide the Gulf of Mexico’s first proven spill containment system and are honored by its the recent endorsement from BOEMRE Director Bromwich,” said Owen Kratz, CEO of Helix. “We firmly believe that our proven, industry-led solution is critical to establishing confidence in the industry’s ability to respond to potential blow out incidents in the region.”

assets such as Balboa and add shareholder value.” Apache assumed operatorship of Balboa with the acquisition of Mariner Energy in November 2010. The field commenced production on Dec. 28, 2010.

Technip wins gathering system contract Enbridge Offshore Facilities LLC has awarded a contract to Technip for development of a gas gathering system in the Walker Ridge area of the Gulf of Mexico. Water depth is 7,000 ft (2,130 m). The contract covers engineering, fabrication, and installation of 160 mi (270 km) of steel catenary risers and pipelines as well as the installation of subsea equipment. Technip in Houston will manage the project. The pipeline and risers will come from the spoolbase in Mobile, Alabama. Installation is scheduled for 2113 using the Deep Blue pipelay vessel.

Apache provides P&A update Production starts from the Balboa field Apache Corp. reports that hydrocarbon production has begun at its Balboa field, located on East Breaks block 597 in the Gulf of Mexico. Initial gross flow rates have stabilized at approximately 30 MMcf/d of natural gas and 1,400 b/d of oil. Apache’s subsidiary is the operator of the field and holds a 50% working interest. Balboa is located in estimated water depths of 3,350 ft approximately 130 mi south of Galveston, Texas. The field is a one-well development with a six-mile tieback to the Anadarko-operated Boomvang spar on East Breaks 643. The reservoir features oil-bearing sandstones with a natural gas cap. The well has been completed near the crest of the structure to optimize overall hydrocarbon recovery. This completion was designed to initially produce natural gas and liquids with increasing liquids and decreasing gas volumes throughout the life of the field. “Subsea tieback technology has significantly improved the economics for deepwater developments by lowering the threshold for commercial accumulations,” said John Crum, co-chief operating officer and president–North America. “Through acquisitions completed in 2010, Apache now has both the capability in-house and the portfolio of properties in the deepwater Gulf of Mexico to exploit

Apache Corp. reports that a subsea survey by an ROV in the vicinity of East Cameron block 278 platform B in the Gulf of Mexico is continuing in order to identify the source of a water disturbance identified on Sunday, Jan. 16. No sheen or other evidence of hydrocarbons were visible as of Jan. 18, the company said. Results of the ROV survey will determine the next steps in responding to the water disturbance. Wells on the platform had not been in production for several years. Apache had initiated P&A operations when the water disturbance was sighted. Prior to shutting in the platform for P&A operations, the platform was processing approximately 20 MMcf/d from other facilities.

InterMoor opens new Morgan City facility InterMoor, an Acteon company, has opened of its new 24-acre facility in Morgan City, Louisiana, announced InterMoor President Tom Fulton. This ISO 9001:2008 approved site contains a fabrication facility that includes two fabrication buildings, both with capabilities to design and produce comprehensive offshore mooring systems, subsea foundations and equipment. This facility has more than double the capacity of InterMoor’s former yard in Amelia, Louisiana. 



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SUBSEA SYSTEMS

Statoil awards world’s first subsea gas compression contract Aker Solutions has been awarded the Åsgard subsea compression system contract by Statoil. The contract value is approximately NOK 3.4 billion ($582.7 million). Aker’s scope of work includes a subsea compressor manifold station, subsea compressor station template structure, three identical compressor trains, all electrical control systems, high voltage electrical power distribution system, topside equipment, and tooling, transport and installation equipment. Åsgard is at Haltenbanken outside Norway in water depths varying from 240-310 m (787-1,017 ft). The Midgard and Mikkel reservoirs contain gas and condensate that are transported through long distance flowlines to the Åsgard B platform. The project will be managed out of Aker Solutions’ in Oslo, Norway, while the equipment primarily will come from Aker Solutions’ facilities in Egersund, and Tranby, Norway, and in Aberdeen, UK. Final equipment deliveries will be made in stages with the manifold station and the compressor station template delivered in 2013 and the compressor trains, controls, and power equipment delivered in 2014. “This award signifies a quantum leap for subsea gas compression within the oil and gas industry,” said Mads Andersen, executive vice president of Aker Solutions’ subsea business area. As reservoir gas is produced, reservoir pressure decreases and the well flow may need boosting in the form of compression. In many instances, subsea compression technology is necessary to create enough pressure for the hydrocarbons to travel up the pipelines to the receiving terminal. “We are extremely pleased to be chosen for this huge milestone contract with Statoil. The synergies we have developed with Statoil on the Ormen Lange gas compression pilot project have given us valuable experience which we can now transfer to this project,” said Andersen.

Chevron contracts subsea work at Jack, St. Malo Technip has won a contract from Chevron North America Exploration and Production to develop the Jack and St-Malo fields, in the Walker Ridge area of the Gulf of Mexico at a water depth of approximately 7,000 ft (2,100 m). The contract covers the engineering, fabrication, and subsea installation of more than 53 mi (85 km) of 10 ¾-in. outside diameter of flowlines, steel catenary risers, pipeline end terminations, manifolds, pump stations, and tie-in skids. Technip in Houston will handle project management. The flowlines and risers will be weld-

Gene Kliewer • Houston

ed at the spoolbase in Mobile, Alabama. Offshore installation is scheduled to use Technip’s deepwater pipelay vessel Deep Blue in 2013.

Shell, FMC to work on multiple projects FMC Technologies Inc. has agreed to supply subsea and topside systems for Shell Offshore Inc.’s West Boreas field development in the GoM. West Boreas is in Mississippi Canyon block 762, in water depths of approximately 3,100 ft (945 m). FMC’s scope includes six 15,000 psi (103 MPa) subsea production trees, subsea and topside controls, one manifold, and related systems and equipment. Deliveries are to start in 3Q 2012. “West Boreas will be the first field to utilize FMC’s 15,000 psi enhanced vertical deepwater tree system,” said John Gremp, president and COO of FMC Technologies. “It is also the first tieback to Shell’s new Olympus tension leg platform, and we are pleased to support this development with our leading subsea systems and services.” Shell also has contracted FMC Technologies to supply subsea and topside systems for the Cardamom Deep project, also in the GoM. Cardamom Deep is a subsea tieback to Shell’s Auger TLP. The field is in Garden Banks block 426 in the eastern Gulf of Mexico in water depths of approximately 2,860 ft (872 m). FMC’s scope includes five 15,000 psi subsea production trees, subsea and topside controls, manifold and tie-in equipment, and other systems and services. Deliveries are to start in 3Q 2011.

Statoil awards $75 Million Vigdis North-East project FMC also has agreed to supply Statoil subsea production equipment to support the Vigdis North-East development. The award has a value of approximately $75 million. Vigdis North-East is a fasttrack oil and gas field in water depths of approximately 920 ft (280 m) in the Norwegian sector of the North Sea. FMC’s scope includes the manufacture of four subsea trees, one manifold, subsea and topside control systems, and an umbilical. The equipment will be based on a standard subsea designed by FMC for Statoil. Deliveries are to start in 3Q 2011.

Petrobras places $74 million order with Cameron Cameron has an order from Petrobras for 27 subsea trees and related equipment worth approximately $74 million for use offshore Brazil. The order represents the remaining trees under a 138-tree frame agreement announced in September 2009. Cameron received a purchase order for the initial 111 trees and associated equipment at

the time the frame agreement was signed. Deliveries of the trees are scheduled to begin during 2011 and continue over four years. Cameron President and CEO Jack B. Moore said, “We are pleased to have the opportunity to build on our history as a primary supplier of equipment and services in the Brazilian market, and we look forward to continuing our support of Petrobras’ developments and our ongoing investment in Brazil.” Moore noted that the trees included in this latest order incorporate enhanced drillthrough capability that will provide significant cost and time savings.

Hess contracts South Arne pipeline bundle Subsea 7 Inc. says now that the North Sea Pipeline Bundle contract award it announced late this past year is with Hess ApS for the South Arne field in the Danish sector of the North Sea. The contract value exceeds of $55 million. The Subsea 7 work scope is to engineer, procure, fabricate, install, and commission a 2.2 km (almost 1.4 mi) bundle system. Also in the scope are the associated subsea tie-ins and testing and pre-commissioning works. The pipeline bundle system will be installed using the controlled depth tow method (CDTM) and will connect two new platforms, Well Head Platform East and Well Head Platform North. The two platforms are scheduled to be installed in the South Arne field in 2012. Engineering is at Subsea 7’s Stavanger, Norway, office. Fabrication will be at the company’s North Sea bundle fabrication site in Wick, northern Scotland, in 2Q 2011, with offshore operations scheduled to commence in late 2011. South Arne is in the Danish sector of the North Sea, in block DK 5604/29. The water depth is 60 m (197 ft). The pipeline bundle technology is unique to Subsea 7, the company says. It allows efficiencies by incorporating the required flow lines, water injection, gas lift, and control systems within a steel carrier pipe. At each end of the pipeline, the structures, manifolds, incorporating equipment, and valves, designed to the requirements of the field, are attached. The fully tested system then is launched and transported to the site using the controlled depth tow method. The CDTM developed by Subsea 7 involves the transport of pre-fabricated and tested pipelines, control lines, and umbilicals in a bundle configuration suspended between two tow vessels. Once launched from the onshore site, the bundle is transported to its offshore location at a controlled depth below the surface. On arrival at the field, the bundle is lowered to the seabed, maneuvered into place and the carrier pipe is flooded to stabilize the bundle in its final position. 



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VESSELS, RIGS, & SURFACE SYSTEMS

Noble to construct two ultra-deepwater drillships Noble Corp. has contracted with Hyundai Heavy Industries Co. Ltd. for the construction of two ultra-deepwater drillships. Deliveries are expected in 2Q and 4Q of 2013 at a cost of $650 million each. The rigs are to be based on a Hyundai Gusto P10000 hull design for operations in waters of up to 12,000 ft (3,656 m), although either may be outfitted for less depending on specific contract requirements. Each unit will have DP-3 station keeping, the ability to handle two complete BOP systems, a heave compensated construction crane to facilitate deployment of subsea production equipment and accommodations for up to 200 personnel.

MIS commemorates MENAdrill I sail away UAE-based MIS Group has announced the sail away of Hull 109 (MENAdrill I) from its Sharjah-based yard, following settlement of final payments from its client, MENAdrill Investment Company. Launched in 2008 by Bahrain’s First Energy Bank, MENAdrill will focus on providing contract drilling services for offshore exploration and development in the Middle East, North Africa, Southeast Asia and others.

Bruce Beaubouef • Houston

Safe Bristolia, and Safe Caledonia were idle during the final quarter of 2010. The Safe Bristolia and Safe Caledonia both underwent annual maintenance work in this period.

Aker finalizes vessel specs for AMC Connector Vessel specifications for the subsea installation and construction vessel AMC Connector are finalized, reports Aker Solutions. The vessel will target deepwater installation with a payload capacity of 9,000 metric tons (9,921 tons). Previously called Aker Connector, the specifications call for two turntables for high-voltage power cables or umbilicals. One is to have 6,000 metric ton capacity on deck and the other 3,000 metric ton capacity below deck. The vessel is 157 m long and 32 m wide with a transit speed of 16 knots, Aker says. The vessel will be equipped with two heave-compensated offshore cranes – with 400 and 50 metric ton (441 and 55 ton) capacity respectively – that can operate down to 3,000 m (9,842 ft) water depth. She will have two 3,000 m depth capacity ROVs onboard and can accommodate 140 people. One feature is the vessel’s deck flexibility. In about two days the ondeck modules can be removed to give a total space of approximately 1,500 sq m (16,146 sq ft). This will enable transport and installation of large spools and jumpers as well as subsea structures and manifolds. AMC Connector is built by STX Europe and will be outfitted at their yard at Søviknes, Norway. She will be ready for operations from 1Q 2012. Subsea power cable provider ABB has secured the vessel for installation campaigns during 2012 and 2013. The vessel will be owned 50/50 by Aker Solutions and Singaporebased Ezra Holdings Ltd., which recently acquired 100% of the shares in Aker Solutions’ subsidiary Aker Marine Contractors AS.

Construction of the Hull 109 (MENAdrill I) took place at the MIS Group’s Sharjah-based yard.

The rig departed on board a heavy lift vessel from MIS’ quayside following a small ceremony to celebrate the event attended by executives from the MENAdrill, MIS, and Noble Denton teams. The construction of the rig at MIS’ yard was supervised by a team from GL Noble Denton on behalf of the owner. Its sister rig, Hull 110, is scheduled for delivery early next year. The construction of the rig at MIS’ yard was supervised by a team from GL Noble Denton on behalf of the owner. Its sister rig, Hull 110, is scheduled for delivery early next year.

Prosafe wins support role extension on Valhall BP Norge has exercised two three-month options for the use of two Prosafe-owned accommodation rigs at its Valhall development in the Norwegian North Sea. The first three months, starting in July, covers the continued use of the MSV Regalia. The Safe Scandinavia will take over for the remaining three months from October onwards. Prosafe says the value of these exercised options is around $44.9 million, and it has been granted a further two-month option which would come into effect next January, if exercised. In the UK North Sea, the company has a Letter of Intent to provide the accommodation support rig Safe Scandinavia for an unnamed project. The firm period of this award is four months, with on-site operations scheduled to start in August 2012. Among the company’s other rigs, the Safe Concordia, Safe Astoria,

Heerema Marine Contractors’ new deepwater monohull construction vessel Aegir is currently being built in South Korea.

Heerema names newest construction vessel Heerema Marine Contractors’ new deepwater monohull construction vessel will be named Aegir, after the Norse god of the sea. The vessel, under construction in South Korea, will be capable of executing wide-ranging infrastructure and pipeline installations in ultradeepwater, and installations of fixed platforms in relatively shallow water. Aegir will complement HMC’s existing fleet, comprising Thialf, Hermod, Balder, and the tugs Retriever and Husky.

MODEC/AMC team on Angola FPSO MODEC Offshore Production Systems (Singapore) has awarded Aker Marine Contractors (AMC) a $30-million installation contract to hookup the Bourgogne FPSO offshore Angola. The FPSO will serve BP’s deepwater PSVM (Plutão, Saturno, Vênus, and Marte) development in block 31 offshore Angola. It will be installed in a water depth of around 2,000 m (6,652 ft), with an oil production capacity of 157,000 b/d. Project management and operations planning for the PVSM contract will be performed from Aker Solutions’ offices in Houston. 



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DRILLING & PRODUCTION

When yes is no Oil companies and support industries with US Gulf of Mexico operations have been collectively holding their breaths in anticipation of the next turn of events to emerge from Washington. They know from experience that bureaucratic decisions have the force of law. Seemingly benign rule changes can – and have – cost them billions of dollars in lost revenue, higher operating costs, and increased overhead. They got a glimpse of the future recently in a speech by Michael Bromwich, director of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE). Bromwich spoke at the Center for Strategic and International Studies Gulf Oil Spill Series in Washington, D.C. Although it was not reported widely – if at all – in the mainstream, it holds abundant evidence of how the new look of GoM regulation will affect the industry, and it isn’t encouraging. Take the following example of when “we won’t change the rules” translates into “we will change the rules.” It isn’t remarkable by its scarcity – Washington is fluent in double talk – but gets the gold star for pure audacity. On the off chance that you think we are being facetious, note the following comments from his presentation: “Over the past few months, especially since our new rules were announced at the end of September, we have heard from countless companies, trade associations, and Members of Congress about the significant anxiety that currently exists in the industry that we will soon change the rules of the permitting process significantly, thereby creating further uncertainty about what is required to conduct business on the OCS. “The phrases we hear repeatedly are that we are ‘changing the rules’ and ‘moving the goalposts’ – the implication is that we have other regulatory requirements up our sleeve that we have not yet unveiled. This is not the case. Barring significant, unanticipated revelations from investigations into the root causes of the Deepwater Horizon explosion that remain in process, I do not anticipate further emergency rulemakings. Period.” That would seem to slam the door on any significant changes to the rules of the game in the Gulf of Mexico, wouldn’t it? However, he goes on: “But…” (you just knew there was going to be a “but”) “…at the same time, we can no longer accept the view that the appropriate response to a rapidly evolving, developing and changing industry, which employs increasingly sophisticated technologies, is for the regulatory framework and the applicable rules to remain frozen in time. Over time, the regulatory framework and the specific requirements must keep pace with advances in the industry – and with industry ambitions to drill in deeper water in geological formations that have greater pressures.” Translation: We are going to change the rules.

Eldon Ball • Houston

those conflicts by clarifying and separating missions across three agencies and providing each of the new agencies with clear missions and new resources necessary to fulfill those missions…” The revenue collection arm of the former MMS became the Office of Natural Resources Revenue. Over the next year, the offshore resource management and enforcement programs will also become separate, independent organizations: • On the one hand, the new Bureau of Ocean Energy Management (BOEM) will be responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way. • On the other hand, the new Bureau of Safety and Environmental Enforcement (BSEE) will enforce safety and environmental regulations. Continuing to quote: “Over the past several months, we have been gathering the facts that are necessary to complete the reorganization in the most rational and sensible way. We have been busy interviewing Bureau employees in all of our regional offices; collecting and analyzing data relating to the Bureau’s processes, systems and regulatory metrics; and developing various models and options for restructuring and reforming the Bureau. This work has been painstaking and time consuming, but it is critical to inform decision-making regarding the transformation of the Bureau.” According to Bromwich, the design will be shaped by the following concepts: • “We will separate resource management from safety oversight to allow our permitting engineers and inspectors greater independence, more budgetary autonomy, and clearer senior leadership focus. The goal is to create an aggressive and toughminded but fair regulator that can effectively evaluate the risks of offshore drilling, will promote the development of safety cultures in offshore operators, and will keep pace with technological advances.” • “We will provide a structure that ensures that thorough environmental analyses are conducted and that the potential environmental effects of proposed operations are given appropriate weight during decision-making related to resource management in BOEM. That structure must ensure that leasing and plan approval activities are properly balanced. These processes must be both rigorous and efficient so that operations can go forward in a timely way – but they must be based on a complete understanding of the potential environmental effects of those operations. We must also ensure that appropriate mitigation of those potential environmental effects are in place.” • “We will also strengthen the role of environmental review and analysis in both organizations through various structural and organizational mechanisms.”

What it really means The new BOEMRE You knew that the old MMS was being replaced, but did you know that no sooner than BOEMRE replaced it, BOEMRE itself would be morphed into a new creation. As Bromwich later outlined in his talk before the Center for Strategic and International Studies, here are some changes that are coming – to distinguish them from the changes that “aren’t” coming. “MMS – with its conflicting missions of promoting resource development, enforcing safety regulations, and maximizing revenues from offshore operations and lack of resources – could not keep pace with the challenges of overseeing industry operating in U.S. waters,” he explained. “The reorganization of the former MMS is designed to remove

Clearly, no one would argue that it is not critically important to protect human life and the environment, and that government must provide the structure for implementing and ensuring this process. We all want that. That isn’t the point. The point is that a new overburden of bureaucratic oversight, control, and expense is being created far beyond what is needed. It amounts to all the things it says it isn’t – “that we have other regulatory requirements up our sleeve that we have not yet unveiled,” as Bromwich put it. We can’t read Bromwich’s remarks and think anything other than that this government does have new regulatory requirements up its sleeve. And the industry will learn of them soon enough. 



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GEOSCIENCES

Gene Kliewer • Houston

BP, Geotrace join to further POCS to fill data gaps BP and Geotrace, are joining for more POCS technology development. Projection Onto a Convex Set (POCS) originated at BP for use in interpolating or reconstructing seismic data during processing. POCS uses information surrounding the acquired data that may be missing, such as in a particular reservoir formation, 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.

Shell, Schlumberger partner to boost recovery factors, extend field life Shell and Schlumberger have signed a multiyear research technology cooperation agreement to improve the recovery factor of oil and gas reservoirs and to extend the life of existing oil and natural gas fields. “This agreement marks another step towards executing our technology strategy by driving delivery of energy solutions through open innovation. The cooperation will enable us to continuously improve recovery factors while at the same time lowering unit costs,” said Gerald Schotman, chief technology officer for Royal Dutch Shell. The combination of Schlumberger’s formation evaluation and reservoir characterization technology with the subsurface laboratory and reservoir expertise of Shell is expected to result in better tools and methods to obtain better field data, better and more efficient numerical models, and enhanced field development methods. This collaboration adds to work Shell and Schlumberger already conduct, and will focus on reservoir surveillance for enhanced oil recovery (EOR) projects, and Digital Rock for detailed numerical modeling of reservoir rocks. “With much of the world’s existing reserves only producible through enhanced recovery techniques, this joint approach aims to unlock these resources in a smart and efficient manner and to shorten time to full field development,” said Ashok Belani, president, Schlumberger Reservoir Characterization Group. The Surveillance project will explore the design, development, and testing of new tools specifically for EOR. These tools and techniques are expected to deliver more accurate field data and to accelerate EOR feasibility studies and pilot projects. The Digital Rock project targets better ways to forecast displacement and recovery at the macroscopic pore scale, as well as methods to scale up core and pore-scale work to reservoir level for both sandstone and carbonate fields.

New entry in seismic arena New marine seismic data acquisition companies do not pop up often, but one seems to be on the way. The Dolphin Interconnect Solutions ASA proposes to NOK 360 million ($61.4 million) in a private placement in connection with Dolphin’s planned entrance into the marine seismic industry. The company expects total investments in connection with establishing a marine seismic division within Dolphin to be in the area of NOK 800 million ($136.5 million). Dolphin has decided to establish a division to offer a full range

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Bergen Oilfield Services has agreed with authorities from Senegal, Gambia, AGC, Guinea Bissau, and Guinea Conakry to acquire, process, and promote a new 2D long offset multiclient data set for the purpose of promoting better understanding of the MSGBC basin. This 2011 survey is scheduled to consist of a regional program of 15,000 2D km (9,321 mi) lines from Senegal to Guinea Conakry. The program is designed in conjunction with input from Exploration Geosciences Ltd. The BOS NWAAM 2D survey will provide a new geophysical data base unconstrained by national boundaries to give exploration companies a unique regional overview of one of Africa’s last relatively unexplored shelf areas The NWAAM survey aims to encourage current licensees to reevaluate existing interests in a regional context, as well as to discover new exploration leads.

of marine geophysical services, including contract seismic, multiclient, and processing partnerships. Chairman of the Board of Dolphin Atle Jacobsen commented that the “outlook in the offshore market looks promising and we expect strong growth in demand for seismic services. 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.”

BOEMRE awards Atlantic Ocean seismic impact study The ongoing saga of whether to drill or not off the US East Coast has taken another turn. The Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) has awarded a task order to develop a Geologic & Geophysical Programmatic Environmental Impact Statement for mid- and south Atlantic waters. CSA International Inc. will evaluate potential environmental effects of multiple exploration activities including seismic surveys. The report “will identify potential environmental effects and inform decision makers and the public of reasonable alternatives to avoid or minimize adverse impacts and guide decision making about seismic research in the region and decisions about where to allow oil and gas leases, placement of renewable energy infrastructure, and development of non-energy mineral resources.” The draft report is expected to be available for public comment sometime this year with the final version in late 2012. 



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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

Sid Snitkin • Spotsylvania, Virginia

Asset information management for offshore platforms Sid Snitkin

ARC Advisory Group Good asset information is fundamental to good asset performance. Everyone involved in operating and maintaining an offshore production platform needs appropriate asset information to do his or her job. For optimal performance, this information has to be complete, accurate, and comprehensive to support a multitude of questions about the asset’s creation, use, and care. Access to the information must also be convenient so that people can use it to make good decisions. Studies have identified poor asset information management (AIM) as the root cause of many asset performance problems, such as poor asset utilization, low maintenance efficiency, high MRO costs, and others. ARC estimates the costs of poor AIM for a typical asset-intensive organization to be 1.5% of sales revenues – a staggering burden for any company today. Poor AIM also increases the risk of safety, health, and environmental incidents, which can jeopardize an enterprise’s very survival. While the opportunity for improvement is incredible, many organizations continue to suffer the pains of poor AIM. Some don’t recognize the opportunity. Others understand that they have problems, but don’t know how to solve them or can’t justify the required investments.

Value of good AIM Every organization, regardless of how well it manages its operations, should consider AIM as a significant opportunity for improvement. Our research indicates that better AIM can improve the performance of most facilities, both financially and otherwise. Furthermore, the typical asset-intensive facility can reap annual savings equal to 1.5% of its sales revenue. Better AIM represents a staggering opportunity, especially for large organizations in industries with distributed operations, such as offshore energy production, as these organizations can implement enterprisewide AIM strategies. However, as the savings are annual, even smaller organizations can benefit by including AIM in

their continuous improvement programs. To assess the financial impact of poor AIM on production asset performance, every company must consider three different areas – revenues, operating and maintenance costs (OPEX), and the capital costs of modifications and upgrades (CAPEX). Poor AIM significantly impacts all three and the effects are cumulative with respect to overall financial performance. Comparing ARC’s estimates of the potential economic benefits with related studies indicates that losses due to AIM may be even larger than we’ve estimated, clearly supporting our call for immediate action. While we’ve focused largely on the financial benefits up to this point, it is important to recognize that a good AIM strategy can improve asset performance across all performance metrics, including EH&S (environmental, health, and safety) and sustainability. Too often, organizations discount non-financial performance benefits when evaluating IT opportunities. In the case of AIM, a good strategy can help the organization avoid significant financial penalties and other effects that might jeopardize the organization’s reputation and very survival.

Asset information categories Energy companies have many kinds of assets. ARC’s ALM research focuses on one specific class of assets – the facilities, technology, and infrastructure that organizations acquire to service their stakeholders. Normally, the distinguishing feature of these kinds of asset investments is that they are physical (as opposed to financial, intellectual property, brand image, etc.). But they also include significant investments in people to operate and maintain production assets (offshore or onshore) and the best practices needed to ensure that they do so efficiently and effectively. Further, these complex investments have long lifetimes and span a series of lifecycle stages, including plan, design, procure, install, commission, operate and maintain, modify, and retire. With this understanding of “asset,” we define asset information as all information created about all the organization’s assets through-

out their lifetimes, including information about physical entities, people, and processes. Enabling people to understand and manage their “real” assets is challenging and means that asset information has to encompass a wide range of information. Ideally, it will be able to support any reasonable question about any asset from any valid stakeholder, whether part of the organization or part of the organization’s APM ecosystem. This includes questions about the physical asset; how it should be used and cared for; and how it was created, used, and cared for in the past so performance can be analyzed and improved. There are many ways to categorize specific asset information content. The categories in the following chart represent a useful breakdown to demonstrate the breadth of AIM. The first thing to note about these categories is how we have segregated the content into two major groupings, reference data, and activity records. Reference data needs to be managed for change. Activity records, on the other hand, represent information about events that have occurred. These are not subject to change, so they don’t need change management. We’ve further broken down these two major groupings into several information categories. Each category supports a different kind of question about the asset. Reference data categories support questions about the asset’s function and capabilities; its physical design; and how people can install, assemble, operate, and maintain the equipment safely and efficiently. Activity record categories support questions about current asset performance and how an asset was operated and maintained in the past. Organizations need this information to identify the root cause of problems and incidents as well as to take advantage of prior agreements, warranties, etc. These information categories provide a helpful checklist of things that organizations developing AIM strategies should consider. Organizations may choose different categories, but they still need to ensure that their scope supports the wide diversity of questions that may arise regarding the asset. 

What information is needed for APM? Asset information spans many info categories. Function • Process Specs • Process Models • Process Calcs • Flow Diags • Equip Calcs • Equip specs • Functional designs

Design • Process design • P&ID • Equip Layout, Design, BOMs • System detail design • MRO BOMs

Reference data

Procedures • Install/test • Descriptions of operation • Operating • Inspections and maintenance • Certification requirements • Lockout & safety requirements

Commercial • Financial analysis • CAPEX • Depreciation • OPEX • Purchasing records • Warranty and repair records • C&M service agreements

Status • Procurement • Operational status • MRO inventory

History • Source and build history • Operating history • Maintenance history • Inspection records • Incident reports • People certifications

Activity records



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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

US Spill commission hands down recommendations

F. Jay Schempf

Contributing Editor

T

he word is spreading across the land: • The Gulf of Mexico is a unique natural resource that provides Americans everywhere with food, energy, and jobs that are essential to the prosperity, security, and welfare of the nation. • For too long the Gulf region has been treated as a place apart, a place to pay the price for and bear the risk of the United States’ costly dependence on oil. • It is a national treasure, and needs to be treated like one, and the time to act is now. This is news? Apparently so, at least to one member of President Barack Obama’s hand-picked panel of seven public figures who make up the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. The above points are faithful to statements in an article written by Frances Beineke, one of the commissioners, for news network CNN and published on Jan. 13, a day after the group released its final report to the president. In addition to her commissionership, Ms. Beineke is president of the National Resources Defense Council, a New York City-based non-profit, international environmental advocacy group with offices in Washington, San Francisco, Los Angeles, Chicago, and Beijing. Similar epiphanic conclusions have percolated upward into the hearts and minds of those who were handed the responsibility for recommending what should be done in the aftermath of the “worst environmental disaster in U.S. history,” i.e., the Deepwater Horizon rig explosion and oil spill in the Gulf in April 2010.

Rocks being rinsed off to remove oil either on or below them on the coast of Grand Isle, Louisiana.

to mitigate risk, particularly for deepwater operations, are showered throughout the suggested reforms.

The ‘personal’ side Included in the printed report are scores of personal stories of victims of the incident and its oil spill aftermath, illustrating – time after time – their financial, domestic, and mental suffering. These apparently emanated from stories told by Gulf Coast residents in testimony before commissioners during regional public meetings.

Findings ‘telegraphed’

What happens next?

Actually, the panel’s overall conclusions held few surprises, since most of them already had been telegraphed by co-chairmen Bob Graham and William Reilly long before the final report was released. Already reported out of the committee – along with the recognition of the GoM as a special region as noted above – are the following points: • The event could have been prevented • Deepwater exploration and production has risks for which neither the industry nor federal, state, and local government are prepared (a claim that is challenged by the industry) • Fundamental reform is necessary to assure human safety and environmental protection. Regulatory oversight of offshore leasing, exploration, and production needs reform in both structure and decision-making • Technology, laws, and regulations, as well as practices for containing, responding to, and cleaning up oil spills lags behind the risks associated with deepwater drilling. Government must close the gap and industry must support – rather than resist – the effort. Also recommended is creation of an independent offshore safety and environmental science agency within the Interior Dept., commanded by a director appointed by the President, who would serve a multi-year term. Various new fees and increases in existing ones, all to be paid for by the industry, along with general mandates and requirements for operators, drilling companies, and other offshore service providers

A lot of the commission’s findings mirror those already made by various members of the Obama cabinet, particularly Interior Sec. Ken Salazar and his point man Michael Bromwich, director of BOEMRE, the successor to the MMS. Bromwich, with extremely broad powers, already has instituted – using presidential mandate – a number of sweeping reforms in regulation of the offshore petroleum industry. The EPA, too, is more active with regard to GoM environmental matters, and literally scores of commissions, congressional committees and various scientific groups working under federal authorization have jumped with all feet into the mix. From the oil spill committee’s report, it is evident that the scientific community could well become much more active in the oversight of offshore activities, including permitting and drilling operations. All in all, everything suggested by the committee, if enacted, would cost a great deal of money. A portion of it would certainly come from the petroleum industry as an added cost for the privilege of drilling in US waters. However, from where the lion’s share of the cost would come remains to be seen, given that federal and state government treasuries are hard pressed these days. And who will be in charge of such spending, should it come about? It’s anyone’s guess. But it’s a safe bet that all the organizations and politicians and multiple interests involved would, and will, be vying for their shares of the authority to spend it. In any case, the overriding hope is that the long-suffering US GoM will be the eventual prime beneficiary. 



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RIG MARKET REVIEW

Reviewing the world offshore rig market Latest forecast sees improved global fleet utilization Matthew Donovan

Marine Market Analyst ODS-Petrodata

T

he worldwide offshore rig market continues to suffer from oversupply as new rig deliveries outstrip demand. As new rigs built to ever-higher specifications are delivered, older rigs have more trouble securing contracts. The number of mobile offshore drilling units under contract worldwide is currently 572, almost identical to the number of rigs under contract at this time last year. However, there are now 790 rigs in the worldwide drilling fleet, compared to the 749 in existence in January 2010. With the increase in fleet size, worldwide offshore rig utilization is now

72.4%, down from 76.5% a year ago. According to ODS-Petrodata’s RigBase market intelligence tool, 104 mobile offshore drilling rigs are under construction or on order around the world, with 57 of these rigs scheduled for delivery this year. Only 30 of the rigs set for delivery this year have contracts lined up.

Gulf of Mexico The Macondo disaster and its aftereffects proved an annus horribilis for the U.S. Gulf of Mexico. From the perspective of the offshore industry, a federally imposed moratorium on deepwater drilling halted the issuing of new deepwater permits. Even with the moratorium now officially over, the Bureau of Ocean Energy Management, Regulation, and Enforcement has not been forthcoming with new deepwater permits, and regulatory

changes have resulted in a sharp reduction in the number of shallow water permits issued. This has done additional damage to the shallow water rig market, which had just been showing signs of revival after being battered by low commodity prices and general economic malaise in 2009. Offshore rig fleet utilization in the U.S. Gulf is now 47.6%, down from an already-anemic 55.9% utilization rate in January 2010. Of the 126 rigs in the region, 60 are under contract. Jackup utilization is only 37.3%, while semisubmersible utilization languishes at 69.2%, down from 100% a year ago. Drillship utilization has remained 100%, and, although only three rigs are actually working, all of the 11 units that remain in the area still have contracts and/or contract commitments. Despite the grim situation, drilling in the U.S. Gulf is expected to resume in some fash-



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RIG MARKET REVIEW

ion over the next 12 months, and demand is expected to rise for some rigs, according to ODS-Petrodata’s World Rig Forecast Short Term Trends. Jackup demand could go up by as many as nine units by May, before falling again over hurricane season then recovering in the winter months. If the speed of the deepwater permitting process is increased, drillship demand in the U.S. Gulf of Mexico could grow by around six rigs by the end of 2011. However, semisubmersible demand in

the U.S. Gulf is expected to decline somewhat over the next year by one or two units.

Latin America Looking further south towards Latin America, Brazil, Mexico and Venezuela continue to be the major hubs for offshore drilling in the region, although work offshore Trinidad & Tobago, the Falkland Islands and Surinam, and an upcoming drilling campaign in Guyana and Cuban waters will occupy a handful

𰀁𰀵𰀣𰀁𰀁𰀴𰀴𰀁𰀁𰁕𰁂𰀁𰀕𰁏𰁊𰁐𰁕𰀁𰁖𰁔𰀷𰁊𰁔𰁊𰁏𰀁𰀢𰁏𰁕𰁐𰁃𰀏𰀁𰀓𰀓𰀎𰀓𰁂𰁆𰀴𰀁𰀧𰀘𰀕𰀁𰂅𰀕𰀁𰁉𰁕𰀣𰁐𰁐

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𰀁𰀁𰀁𰀁𰀏𰀏𰀏𰀮𰁐𰁐𰁓𰀁𰀁𰀁𰀁𰀁𰀢𰁅𰁗𰁂𰁏𰁕𰁂𰁈𰁆𰁔𰀏

Photo courtesy Vantage Drilling.

𰀥𰁊𰁅𰀁𰁚𰁐𰁖𰀁𰁌𰁏𰁐𰁘𰀠𰀁𰀪𰁏𰁕𰁆𰁓𰀮𰁐𰁐𰁓𰀁𰁉𰁂𰁔𰀁𰁕𰁉𰁆𰀁𰁍𰁂𰁓𰁈𰁆𰁔𰁕𰀁𰁔𰁕𰁐𰁄𰁌𰀁𰁐𰁇𰀁𰁎𰁐𰁐𰁓𰁊𰁏𰁈𰀁𰁆𰁒𰁖𰁊𰁑𰁎𰁆𰁏𰁕𰀁𰁊𰁏𰀁𰁕𰁉𰁆𰀁𰁘𰁐𰁓𰁍𰁅𰀏𰀪𰁏𰁕𰁆𰁓𰀮𰁐𰁐𰁓𰀁𰁉𰁂𰁔𰀁𰁅𰁆𰁔𰁊𰁈𰁏𰁆𰁅𰀁𰁎𰁐𰁓𰁆𰀁𰁇𰁐𰁖𰁏𰁅𰁂𰁕𰁊𰁐𰁏𰀁𰁑𰁊𰁍𰁆𰁔𰀁𰁕𰁉𰁂𰁏𰀁𰁂𰁏𰁚𰀁𰁐𰁕𰁉𰁆𰁓𰀁𰁎𰁐𰁐𰁓𰁊𰁏𰁈𰀁𰁄𰁐𰁎𰁑𰁂𰁏𰁚𰀏𰀪𰁏𰁕𰁆𰁓𰀮𰁐𰁐𰁓𰀁𰁉𰁂𰁔𰀁𰁅𰁆𰁗𰁆𰁍𰁐𰁑𰁆𰁅𰀁𰁂𰀁𰁄𰁖𰁔𰁕𰁐𰁎𰀁𰀗𰀑𰀎𰁕𰁐𰁏𰀁𰁊𰁏𰁍𰁊𰁏𰁆𰀁𰁉𰁆𰁂𰁗𰁆𰀁𰁄𰁐𰁎𰁑𰁆𰁏𰁔𰁂𰁕𰁊𰁐𰁏𰀁𰁔𰁚𰁔𰁕𰁆𰁎𰀏𰀪𰁏𰁕𰁆𰁓𰀮𰁐𰁐𰁓𰀍𰀁𰁂𰁏𰀁𰀢𰁄𰁕𰁆𰁐𰁏𰀁𰁄𰁐𰁎𰁑𰁂𰁏𰁚𰀍𰀁𰁊𰁔𰀁𰁕𰁉𰁆𰀁𰁍𰁆𰁂𰁅𰁊𰁏𰁈𰀁𰁈𰁍𰁐𰁃𰁂𰁍𰀁𰁎𰁐𰁐𰁓𰁊𰁏𰁈𰀍𰀁𰁇𰁐𰁖𰁏𰁅𰁂𰁕𰁊𰁐𰁏𰁔𰀁𰁂𰁏𰁅𰀁𰁔𰁖𰁃𰁔𰁆𰁂𰀁𰁔𰁆𰁓𰁗𰁊𰁄𰁆𰀁𰁄𰁐𰁎𰁑𰁂𰁏𰁚𰀁𰁑𰁓𰁐𰁗𰁊𰁅𰁊𰁏𰁈𰀁𰁊𰁏𰁏𰁐𰁗𰁂𰁕𰁊𰁗𰁆𰀁𰁔𰁐𰁍𰁖𰁕𰁊𰁐𰁏𰁔𰀁𰁇𰁐𰁓𰀁𰁓𰁊𰁈𰀁𰁎𰁐𰁗𰁆𰁔𰀍𰀁𰁎𰁐𰁐𰁓𰁊𰁏𰁈𰀁𰁔𰁆𰁓𰁗𰁊𰁄𰁆𰁔𰀁𰁂𰁏𰁅𰀁𰁐𰁇𰁇𰁔𰁉𰁐𰁓𰁆𰀁𰁐𰁑𰁆𰁓𰁂𰁕𰁊𰁐𰁏𰁔𰀁𰁊𰁏𰁄𰁍𰁖𰁅𰁊𰁏𰁈𰀁𰁆𰁏𰁈𰁊𰁏𰁆𰁆𰁓𰁊𰁏𰁈𰀁𰁂𰁏𰁅𰀁𰁅𰁆𰁔𰁊𰁈𰁏𰀍𰀁𰁔𰁖𰁓𰁗𰁆𰁚𰀁𰁂𰁏𰁅𰀁𰁑𰁐𰁔𰁊𰁕𰁊𰁐𰁏𰁊𰁏𰁈𰀍𰀁𰁇𰁂𰁃𰁓𰁊𰁄𰁂𰁕𰁊𰁐𰁏𰀁𰀁𰁂𰁏𰁅𰀁𰁔𰁖𰁃𰁔𰁆𰁂𰀁𰁊𰁏𰁔𰁕𰁂𰁍𰁍𰁂𰁕𰁊𰁐𰁏𰀏

𰁘𰁘𰁘𰀏𰁊𰁏𰁕𰁆𰁓𰁎𰁐𰁐𰁓𰀏𰁄𰁐𰁎

________________

of units. Current offshore rig fleet utilization in Mexico, Central, and South America combined is at 76.43%. Of the 31 offshore rigs in Mexican waters, 22 are under contract to state oil company Petroleos Mexicanos (PEMEX) for a fleet utilization rate of 70.97%. The Mexican rig market has declined significantly since last January, when 33 out of 36 rigs were under contract. Demand for jackups in Mexico is expected to rise in 2011, assuming PEMEX can deal with certain budget and political woes. An increase in demand for semisubmersibles is also possible, with the number of semisubmersibles under contract to PEMEX potentially increasing by as many as three by mid-year. In South America, 97 out of 123 mobile offshore rigs are under contract for a fleet utilization rate of 78.86%, up from around 76.3% a year ago. Brazil accounts for the vast majority of this activity, boasting a total of 67 rigs under contract to companies such as state giant Petrobras, domestic oil company OGX Petroleo, and international operators like Anadarko, Chevron, ExxonMobil and Repsol YPF. In Venezuela, PDVSA has 24 rigs, most of them Lake Maracaibo barges, either under contract or owner-operated, while one jackup is working in the country for Repsol YPF. Based on currently known drilling plans put forth by operators, demand for semisubmersibles and drillships should rise in South America throughout the next year, due for the most part to work offshore Brazil. For jackups in South America, the story is different, with little change expected in the number of rigs under contract over the course of the coming year.

Europe, Mediterranean and Black Sea The European rig fleet has increased since January 2010, going from 104 units to a current level of 116. The contracted rig count also increased, from 90 to 93, but utilization drooped from 86.5% to 80.2%. Even with this decline, Europe still has the highest fleet utilization of any major rig market.


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RIG MARKET REVIEW

An increase in semisubmersible demand is expected in Northwest Europe over the next year, particularly during late spring to early summer. However, demand will slacken somewhat in the latter half of 2011. This will be coupled with little change in the small European drillship market, so overall the number of floating rigs working in European waters will rise only modestly in 2011. However, number of jackups under contract in the area could rise by 10% or more

by the end of the year. A modest net increase in the number of jackups and floating rigs working in the Mediterranean and Black Seas is also forecast.

West Africa The West African mobile offshore rig fleet has undergone only a small amount of change over the past year. Compared to January 2010,

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17 32 47 48 34 27 16 69 29 26 31 17 56 20 139 608

15 22 29 26 14 23 4 33 8 14 15 14 40 6 73 336

0 5 0 3 1 0 0 2 0 2 4 2 5 0 1 25

1 0 11 13 25 1 9 15 0 4 12 0 1 20 14 126

NW Europe

W Africa

0 1 3 8 0 8 0 10 0 0 4 2 5 0 21 62

0 0 2 0 1 1 0 6 0 5 0 5 5 0 29 54

1 0 19 4 0 10 1 14 29 9 2 0 7 0 9 105

Middle East Asia Pacific Rest of World 6 4 1 8 5 1 6 13 0 4 10 5 2 0 13 78

9 27 8 13 3 5 0 10 0 3 2 2 36 0 42 160

0 0 3 2 0 1 0 1 0 1 1 3 0 0 11 23

Source: ODS-Petrodata RigBase

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RIG MARKET REVIEW

the number of rigs in the region has gone up by a net two to 64, while the number of contracted rigs is the same 48. Fleet utilization is now 71.9%. When broken down by rig type, 11 of 13 drillships, 15 out of 19 semisubmersibles and 20 out of 30 jackups are under contract. Demand for all three rig types is predicted to rise modestly in West Africa this year. New drilling programs offshore Nigeria, Ghana, Angola, and Cote d’Ivoire will drive the majority of the increases.

Middle East The Middle East is a jackup market, and the region’s mobile offshore rig fleet is essentially unchanged from a year ago. Now, 90 out of 119 mobile offshore drilling units are under contract for a fleet utilization rate of 75.6% versus year-ago numbers of 90 out of 118 rigs under contract and a fleet utilization rate of 76.3%. Boosted by Saudi Aramco’s activities offshore Saudi Arabai and the Iranian Offshore

Oil Co. in Iran, Middle Eastern jackup demand is likely to rise during 2011.

Caspian Sea Six rigs are working in the Caspian Sea, with another, Maersk Drilling semisubmersible Maersk Explorer, under contract and expected to begin work in the very near future. The working rigs include three jackups and three semisubmersibles. Current drilling is taking place in Iran, Kazakhstan, Turkmenistan, and Azerbaijan. Azerbaijan is home to two cold stacked rigs and four classed as out of service. These rigs, older units belonging to Azerbaijan’s state oil company SOCAR, are unlikely to enter the market again. Demand is expected to be almost flat throughout 2011 for the Caspian Sea, aside for a small increase in jackup demand which will be easily met by regional supply.

Asia/Australia In the Asia/Australia region, offshore rig fleet utilization is at 76.1%, with 108 out of 142 mobile offshore rigs under contract. Jackup utilization is at 77.4%, semisubmersible utilization is 72.2%, and drillship utilization is 75.0%. In the Indian Ocean, jackup and semisubmersible demand will increase slightly this year, while drillship demand will be essentially flat. In Southeast Asia, slight increases in semisubmersible and drillship demand will be countered by a drop in demand for jackups. In the Far East, major changes in offshore rig activity are not expected this year. In Australia and New Zealand, jackup demand is expected to go up by one or two rigs this year, and the floating rig market could see a similar net increase in the number of rigs under contract.

Day rates

__________

Over time, in normal rig market conditions, day rates tend to move with utilization, although rates generally will drop faster and rise more slowly than utilization. On a worldwide basis, average offshore rig day rates increased slightly over the course of 2010. Rates for 250ft. to 300-ft. rated jackups in the U.S. remained flat, while jackup rates in Northwest Europe fell slightly. Globally, rates for mid-water depth semisubmersibles increased during the second half, but fell back in December, while rates for deepwater rigs rose in the second quarter and then leveled off. ODS-Petrodata’s latest offshore rig demand forecast predicts improved global fleet utilization among all three major rig types, jackups, semis and drillships. However, the gains are expected to be fairly modest for all three, and that foreshadows a similar situation for day rates over the course of the year. 



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ASIA-PACIFIC/AUSTRALIA

Transportation, installation techniques evolving for heavier topside consignments Capabilities increase to meet range of metocean conditions

M

y first job after graduation was with CFEM, a French company that specialized in offshore mobile drilling units, such as barges, semis, and jackups. In the early 1980s, the programs we used to evaluate vessel motions and calculate loads and fatigue were quite primitive compared with those we have today, so there was a greater degree of uncertainty and larger safety factors. The inclination tests we performed on those rigs were a vital check that the weight distribution and our basic calculations were as predicted. When I joined Technip, one of our main objectives was to create platform technology that enabled installation without the need for a large crane vessel. We first developed the

Philippe Weber

Technip

TPG 500 production jackup platform, with its buoyant hull, that could be wet-towed and installed by three tugs. This was a good option for the North Sea, where a large clearance is required below the deck to allow for the highest prevailing storm waves. This option was most economic with very large topside weights, where the cost of the buoyant hull and jacking systems could be offset by the savings in offshore hook-up and com-

missioning that a conventional multi-module offshore installation would entail. But it was also clear that we needed a method of installing large conventional truss topside decks onto conventional piled steel jackets. We initially developed the floatover method for the Middle East region, where we could see a number of suitable projects coming up, but it was challenging at the start to convince oil companies to adopt this new method. Looking back, it seems strange, since floatover has now become the standard procedure for platform topside installations in the area. The first breakthrough was the installation of a 2,500-metric ton (2,756-ton) topsides using the floatover method on EGPC’s

The initial stage of a floatover operation of a large topside onto a fixed piled steel jacket.



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Offshore Ethylene Platform in the Egyptian sector. This installation and the two that followed only used ballasting of the barge supporting the deck, to lower it onto the jacket support posts.

Lowering faster This method was adequate where the sea conditions were calm, but in other areas of the world, in more open seas subject to swell conditions, that barge motions, especially heave, would be excessive. In these cases, the slow speed of ballasting, caused by the need to pump vast volumes of water, would result in an extended period to set the deck down and repeated impacts would cause damage to the topsides, jacket, and foundation piles. A system to lower the topsides deck was required, and this is when the Unideck system was born. The Unideck system uses hydraulic jacks to elevate the topside deck when it is on the barge, and then set it down onto the jacket within less than a minute. It was first tried on the Unideck jacks in 1995 to install Elf’s Cobo platform topside offshore Angola. This was one of the most challenging floatovers, since the long period swell in the Gulf of

A floatover of a large topside onto a floating semisubmersible hull.

Guinea has a resonant effect on the barge transporting the topside, resulting in large heave motions even when the swell height is small. Setting the deck down rapidly with the hydraulic jacks is the best way to install decks by floatover in this part of the world. I remember the relative motions between the

topsides and jacket were quite high before mating, and with a 9,500-metric ton (10,472ton) topside you are dealing with immense forces. The operation was a success and this was the first of many topside installations offshore West Africa, including Exxon’s East Area platform topsides at 18,000 metric tons (19,841 tons).

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ASIA PACIFIC/AUSTRALIA

In the mid 2000s, we turned our floatover experience toward the mating of topsides onto floating structures with the Petrobras series of large semisubmersible platforms P52, P51, and P56. Here, the operation is complicated by the fact that, unlike a fixed jacket, the substructure is floating. Safely coupling two large floating bodies has its own set of challenges, even in sheltered waters. The hull freeboard – the distance from sea level to the top of the hull columns – is

‘

extremely low during these operations and has to be controlled very carefully by ballasting as the weight transfers from the barge to the hull.

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environments where greater under-deck clearances are required. This involves elevating the topside at the construction yard and inserting a support structure, or jacket section, below it prior to load-out onto the transport barge. This provides the topsides with the height required to mate it onto the jacket, but means it is transported at a high level, so the transport barge needs to have a broader beam to provide adequate stability. The jacket, in turn, must to be designed with a larger slot to allow the barge to enter the structure. At some point, as the topside and under-deck clearance becomes ever larger, a conventional steel jacket becomes too big to fabricate, rendering a gravity-based structure, either steel or concrete, the preferred substructure. Over the years there has been a distinct trend towards larger topsides and more extreme environments, requiring higher deck installations. The forthcoming large gas developments offshore North West Australia are a good example of the need for large topside decks to treat the huge gas volumes, in a cyclonic area requiring a high under-deck clearance. There is no doubt that we now have a better understanding of environmental conditions, and the programs we currently use to estimate vessel motions, calculate loads and fatigue are so sophisticated that it removes a lot of the uncertainty we had in the past. These state-of-the-art programs have been calibrated following extensive model testing programs and by using data from full scale installations. Currently Technip is working on a project offshore North West Australia with a topside of around 35,000 metric tons (38,581 tons) and an under-deck clearance of some 26 m (85 ft). This project will take floatover installations in open seas to a new level, but it will not stop there. During the development of Norway’s offshore sector using Condeep platforms, floatovers of almost 50,000 metric tons (55,115 tons) were performed in sheltered fjords. There could be floatovers at around this size onto semisubmersible hulls quite soon, and even possibly in open seas onto fixed platforms within the next 15 years if the barges keep getting larger or if a catamaran configuration is developed. For progress to continue, however, it is absolutely vital that we attract young engineers into the oil and gas business over the next 10 years before the full effects of the “big shift change” are felt. In future, we will develop oil and gas in even more remote and harsher environments, such as the Arctic, and this will require our young engineers to confront a new set of issues. 


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India looks to develop offshore resources Eight deepwater blocks and seven shallow-water blocks to be offered Gurdip Singh

Contributing Editor

I

ndia expects $2 billion in fresh investments to be made over the next eight years in new exploration under the New Exploration Licensing Policy (NELP) IX program, which offers 34 blocks spread over 88,800 sq km (34,286 sq mi), 65% of which is virgin acreage. On offer are eight deepwater blocks, seven shallow-water blocks, and 19 onshore blocks. The investment, to be spread over seven years for oil discovery and eight years for gas discovery, seems conservative, but India offers a challenging environment to international exploration companies, with more flexibility in its production sharing contract and an ever ready domestic market for indigenous oil and gas supply. The Directorate General of Hydrocarbons’ (DGH) open bidding system calls for competitive bids while offering flexibility of operation. DGH seeks aggressive participation work program in competitive bids from exploration companies, no matter where they operate from. Exploration companies are offered tax holidays, full rights to repatriate profits, go solo with their investments or form joint ventures, and all bonuses related to contract signing and hydrocarbon discoveries have been stopped. All equipment and material imports for exploration and field development is duty free with 100% cost recovery on investment. Hydrocarbon exploitation remains the key work for DGH, the past efforts of which have started yielding results. The 60 MMcm/d (2.1 bcf/d) production from the KG DWN98/3 has doubled India’s indigenous gas production to 60 bcm (2.1 tcf) a year. “We are looking for a similar success,” said DGH Director General Sunil Kumar Srivastava. At least four new field development plans are being evaluated by the DGH. A recently acquired 2D data is available for all new blocks under NELP IX, which has seven years for oil exploration and eight years for gas prospecting. It is offering deepwater blocks where carbonate build up shows huge potential, said DGH Chief Geologist Suresh Kumar Tripathy. One block is in the Kutch Sawrasthara with a sand stone reservoir; two blocks are in the prolific Mumbai basin, and two blocks are in the Kerala Konkan to test Mesozoic sediment. The shallow water acreage includes two blocks in the Gujarat Kutch basin, next to drilled wells with hydrocarbon shows. Two blocks are in the hydrocarbon producing Mumbai High basin, and three blocks in Kerala Konkan have hydrocarbon at build up in tertiary sediment. Three onshore blocks are in the Assam and Arakan basin – one in Tripura and two in Assam in the north east of the country. These blocks are within the producing fields, said DGH. Two blocks are in the Vidhyan basin of central India with a lot of gas seepage.

Investment up to NELP VIII • Actual investment on exploration $8.2 billion • Actual investment on development $7.4 billion NELP package: 1. Bidder to be evaluated on the basis annual cost recovery percentage and profit share to the government at two tranches. 2. Profit petroleum to be computed based on assumed capex, opex, production profile for each block, and weighted price and production profile scenarios. All assumptions are available to bidders on the DGH Website. 3. The government profit petroleum shall be computed after a discount of 10% over project life. Crude oil price of $90/60/30 per barrel and gas price of $ 200/150/100 per 1 Mcm (35 MMcf) for high/most likely/low price scenarios ($ 5.5/4.2/2.8 per MMbtu). 4. Bidder offering highest profit share to government as per the above will get maximum points and others will get proportionate points. 5. Fiscal package has a uniform weightage of 50 points. 6. Bank guarantee amount reduced from 35% of annual to 7.5% of the total estimated value of committed work program. 7. No compulsory relinquishment of area after Phase I but, retention would require additional work commitment. 8. Bid bond to be submitted along with bid. 9. Pre-determined amounts for unfinished work program in the form of LD in order to avoid ambiguity in well and seismic cost. 10. Initial exploration period to five years and total exploration period to eight years in respect of deepwater and Frontier areas (NE & Less explored) exploration Period. (One year additional time compared to other blocks). 11. Incentive for offering 3D seismic for the entire block area: to award maximum points earmarked for 2D seismic to bidders offering 3D seismic for the entire block. 12. To waive off 2D seismic mandatory work program (wherever applicable) for bidders offering 3D seismic for the entire block. 13. Initial exploration period to five years and total exploration period to eight years for deepwater and frontier areas (NE & Less explored) exploration period. (One year additional time compared to other blocks). 14. Incentive for offering 3D seismic for the entire block area. To award maximum points earmarked for 2D seismic to bidders offering 3D seismic for the entire block. To waive off 2D seismic mandatory work program (wherever applicable) for bidders offering 3D seismic for the entire block. 15. The ceiling limits for procurement procedures of goods and services are increased considering the rise in input cost in international market. 16. Companies would be eligible for bidding for the earlier relinquished blocks which are now on offer in NELP IX, in case companies find the block attractive enough based on change in geological concept or availability of new technology.



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How can a rig that big operate reliably at any time?

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Ministerial address Addressing the NELP IX road show in Singapore, India’s petroleum and natural gas minister Murli Deora assured investors of level playing fields, dismissing suggestion

of any favor towards the country’s public or private sector companies. He invited exploration and production companies from across the globe to take part in NELP IX bidding, saying the blocks holding

Offshore blocks offered under the NELP IX ● Andaman four blocks – 47,000 sq km (18,146 sq mi); 2D 60,403 km (37,533 mi) and 3D 11,882 sq km (4,588 sq mi) • Block AN-DWN-2010/1 – 5,901 sq km (2,287 sq mi) in water depth of 1,400 m (4,593 ft) to 2,500 m (8,202 ft) • Block AN-DWN-2010/2 – 4,560 sq km (1,761 sq mi) in water depth of 1,400 m to 2,500 m • Block AN-DWN-2010/3 – 9,145 sq km (3.531 sq mi) in water depth of 1,400 m to 2,800 m • Block AN-DWN-2010/4 – 4,197 sq km (1,620 sq mi) in water depth of 1,400 m to 3,000 m ● Guajarat – Kutch offshore basin 36,000 sq km (13,900 sq mi) offshore including deepwater and 35,000 sq km (13,514 sq mi) onshore. 2D 154,974 km (96,296 mi) and 3D 9,729 sq km (3,756 sq mi) ● Gujrat – Kutch basin • GK-OSN-2010/1 – 1,361 sq km (525 sq mi) in water depth of 30 m (98 ft) to 70 m (230 ft). Four exploratory wells have been drilled in the block. • GK-OSN-2010/2 – 1,625 sq km (627 sq mi) in water depth of 60 m (197 ft) to 100 m (328 ft). Five exploratory wells have been drilled in the block ● Gujarat – Saurashtra offshore basin – 240,000 sq km (92,665 sq mi) 2D 4,954 km (3,078 mi) and 3D 8,027 sq km (3,099 sq mi)

high potential for hydrocarbon discoveries. “Invest in Indian E&P and become partners in our progress and our efforts to enhance the energy security of the country,” said Deora, who headed a high-level delegation seeking

• Block GS-DWN-2010/1 – 8,255 sq km (3,187 sq mi) in water depth of 2,000 m (6,562 ft) to 3,100 m (10,717 ft) ● Kerala-Konkan offshore basin – 580,000 sq km (223,939 sq mi) 2D 169,632 km (105,404 mi) and 3D 10,310 sq km (3,981 sq mi). 20 exploratory wells drilled in the area with gas shows in Miocene carbonate and sandstones in three wells and in Cretaceous sandstones in one well • KK-DWN-2010/1 & KK-OSN-2010/1 deepwater and shallow water – 10,019 sq km (3,868 sq mi) in water depth of 2,000 m and shallow acreage in water depth of 65 m (213 ft) to 400 m (1,312 ft) – one exploratory well drilled in shallow acreage • KK-OSN-2010/2 – 1,860 sq km (718 sq mi) in water depth of 65 m (213 ft) to 400 m (1,312 ft) • KK-OSN-2010/3 – 1,874 sq km (724 mi) in water depth of 65 m to 400 m ● Mumbai offshore basin – 236,000 sq km (91,120 sq mi). 2D 267,561 km (166,255 mi) and 3D 63,299 sq km (24,430 sq mi) • MB-DWN-2010/1 – 7,963 sq km (3,075 sq mi) in water depth of 2,900 m (9,514 ft) to 3,200 m (10,499 ft) • MB-DWN-2010/2 – 7,063 sq km (2,727 sq mi) in water depth of 2,900 m to 3,200 m • MB-OSN-2010/1 – 2,998 sq km (1,158 sq mi) in water depth of 90 m (295 ft) to 300 m (984 ft) • MB-OSN-2010/2 – 3,411 sq km (1,317 sq mi) in water depth of 50 m (164 ft) to 400 m.

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E&P participation as well as investors from Singapore-based financial institutions. Investment in the Indian E&P sectors is one of the most lucrative opportunities today for several reasons, he said, including the readily available market for oil and gas, well established independent judiciary, and stable democratic government. The minister also pointed out the facility of single window clearances and assured transparent bids with immediate results of the winners. Director General of Hydrocarbons Sunil Kumar Srivastava expects strong crude oil prices plus surging global and Indian energy demand to attract $2 billion in new exploration investment under NELP IX. He pointed out that Indian attracted $1.1 billion in exploration investment under NELP VIII during the 2008-09 global economic recession. Since its inception in 1997-98, the NELP has secured about $15.6 billion in E&P investment, resulting in 87 oil and gas discoveries in a total of 26 blocks with reserves of more than 640 million metric tons oil equivalent. The Indian government has awarded 235 blocks up to NELP VIII, and would likely go for one more round before offering its acreage on open bid basis. Overall, only 20% of India’s basins have been

explored. Exploration would need to be intensified in 44% of the already tested basins and the remainder is not explored, added Srivastava on new frontiers. India has 1 million sq km (386,102 sq mi) of basins left to be explored while 2.15 million sq km (964,255 sq mi) of the basins have been leased out exploration, he added.

Industry support Delegates at the Singapore road show agreed that Indian NELP rounds had 50% success ratios of hydrocarbon discoveries, one of the best returns in Asia, ahead of prospects in Australia and Southeast Asia. However, India needs to find an “elephant” field with reserves of more than 1 Bbbl to increase share of indigenous resources in the domestic market, and intensify exploration activities, they said. The round closes March 18, 2011, after road shows in Perth (Feb. 1-2), Calgary (Feb. 1011), and Houston (Feb. 14-15). BG, formerly British Gas, plans to submit bids under NELP IX, said its general manager for Asia, Derek Fisher. Addressing the same road show, he underlined BG’s commitment to the Indian hydrocarbon sector. “India is a core country for BG group and focus is on gas. We are actually participating in all segment of the gas chain in India. We

are partner in the offshore Penna, Mukta, and Tapti fields,” he said. BG also has stakes in KG-OSN-2004/1, MN-DWN-2002/2, and KG-DWN-2009/1. Showing its commitment to Indian hydrocarbon sector, Cairn India Ltd. said it has invested $4.5 billion over its 15 years of doing upstream businesses in the Indian energy sector. Cairn Exploration Director David Ginger said the company plans to invest $2 billion in the next two years. And, Cairn would continue to focus on exploration and NELP in the coming years, he added. Meanwhile, Indian national groups ONGC, Oil India, GSPL, and Indian Oil Corp. are among the investors seeking partners for bidding for deepwater acreages under NELP IX. The move would be to share investment risks in the deepwater, where average well could cost $30 million to $60 million. Commenting on the high cost of per well investments, an industry analyst pointed out the steep increases in insurance in upstream sector after the BP’s Macondo blowout in the Gulf of Mexico, and the limited availability of resources. “The NELP has established that India has a clear and transparent process and does not discriminate between private and public sector,” said Vikram Mehta, hydrocarbon chief of the Confederation of Indian Industries. 

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Offshore Asia heads to Singapore March 29-31 New this year is an LNG technology program track

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he annual Offshore Asia Conference & Exhibition heads to Singapore’s new Marina Bay Sands Resort on March 29-31 expecting to expand on its success in 2010. More than 5,000 attendees from more than 60 countries are expected to hear about new technologies, regional trends and challenges, and to see the latest in offshore equipment and services from more than 100 companies. The industry advisory board that leads the conference and has set a Plenary Sessions that features David Paganie, conference director and chief editor of Offshore; Lim Kok Kiang, director of Transport Engineering, Singapore Economic Development Board, welcoming attendees; Jacob Dweck, head of LNG, Sutherland, looking at the impact on global offshore operations of the Macondo disaster in the US Gulf of Mexico; and a regional offshore activity forecast. That opening session will be followed by a technical program with two tracks to cover offshore exploration and production technology and applications. Session topics in the first track include well construction and drilling operations, production optimization, risk management, challenges specific to Asia/Pacific upstream oil and gas operations, flowlines and pipelines, and construction and installation. New this year, the second technical track concentrates on LNG. Topics include commercial and trade issues, supply, markets, analyses, and technology. Tuesday, March 29, registration is open from 08:30 to 18:00, and the exhibition hall is open from 13:00 to 18:30. From 17:00 to 18:30 there will be an Opening Night Reception on the exhibition floor. Wednesday, March 30, registration is 08:3018:00. The Opening Plenary Session runs from 09:00 to 10:00. The exhibition hall opens at 10:00 and the conference sessions at 11:00. Both end at 18:00. Thursday, March 31, registration is from 08:30 to 16:00; exhibitions are scheduled from 09:00 to 16:00, and conference sessions from 09:30 to 16:00. The awards ceremony and closing remarks are set for 16:00 to 16:15. On both Wednesday and Thursday there are coffee breaks and delegate lunches scheduled on the exhibit hall floor. For the most recent registration and sched-

The 2011 Offshore Asia Conference and Exhibition will be in Singapore's new Marina Bay Sands Resort complex.

ule information, see http://www.offshoreasiaevent.com/index.html. Times and locations are subject to change. The advisory board to Offshore Asia consists of Julian Callanan, Infield Systems Ltd.; Dr. Gregory Chiu, Asian Institute of Technology; Tony Findlay, Fluor Offshore Solutions; Gary Foulis, Schlumberger (retired); Mads Hjelmeland, Framo Engineering Asia Pacific Sdn Bhd; Barry J. O’Donnell, Pearl Energy; Phil MacLaurin, Premier Oil; David Paganie, PennWell Corp.; Chandru Sirumal Rajwani, Keppel FELS Ltd.; Brian Reeves, Oil & Gas Field Facilities Consultants Ltd.; Joseph H Rousseau, ABS Pacific; Will Rowley, Acteon; John Samson, Aker Solutions; John A. Sheffield, John M Cambpell & Co.; Rodney Silberstein, ARV Offshore Co. Ltd; Ricky Simic, Oil States Industries Inc.; Geoff Stone, Penspen Ltd./Andres Palmer & Associates; Warren True, PennWell Corp.; Dr. Joko Widjaja, Technip Eng. Thailand Ltd.; and Rene Wit, PDO. Sponsors of the conference and exhibition are ABS; Aker Solutions; Cameron; Oil State Industries; the Gas Association of Singapore; ITF; Singapore Exhibition & Convention Bureau; YourSingapore.com; Offshore magazine; the Oil & Gas Journal; the Oil & Gas Financial Journal; Oil, Gas & Petrochem Equipment; PennEnergy; Energy Asia, LNG OneWorld; Marine, Offshore Shipbuilding, Maps Globe, Offshore Industry, and Orange.

Following are abstracts of some presentations and technologies scheduled for the conference:

Blowout preventer testing— advanced technology development Engr. Charles Franklin

Innovative Pressure Testing LLC A step-change in leak detection/pressure testing using a digital solution rather than the traditional circular chart recorder (CCR) is available. The initial development focused on testing BOP equipment (BOPE) in deepwater. More than 2,000 individual pressure tests were used to validate the Thermally Compensated Leak Detection (TCLD) transform. The transform allows the processing of digital data that shows to be optimum for leak detection. A small leak may not be identified for up to 20 minutes into the high-pressure test using conventional CCR means. The development provides for enhanced leak detection during the low-pressure test. In addition, a slow leak is objectively identified in less than two minutes during the high-pressure test, and a test validated in the regulatory agencies minimum holding time requirements. This is an improvement upon the 15 to 60 minutes or more per individual



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test using a CCR or other methods. The presentation will showcase the assurance, transparency, accuracy, archiving, and efficiency benefits of the new equipment. TCLD delivers a critical rig path time savings of three to 12 hours, every time the BOP and manifold are tested. With the software, procedures and training, more than a week of time savings per deepwater rig year can be saved. Further leak detection and pressure analysis opportunities for pipelines also will be addressed.

Drillstem testing— operational and safety aspects Shangkar Venugopal

Halliburton Well testing costs typically account for approximately one-third of the cost of developing an exploration well. There are many difficulties inherent to these operations. For this reason, it

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is critical that careful planning be considered as the key step in the development of a testing operation that provides the desired parameters of both the operator and the service company in the safest and most cost-efficient manner. This presentation provides insight into the techniques and procedures practiced by Petronas in collaboration with a major service company to provide all the operational and safety steps required for a successful drillstem testing (DST) operation. This testing program uses a structured approach that will guide the user through the best practices necessary to effectively plan and implement a DST operation under just about any circumstance. DST operations must be designed to deal with whatever variables that are defined in the safest, most cost-efficient fashion. The method presented in this paper enables the testing design to address properly the following: • Design parameters for contingency conditions that are not present normally during equipment operations but could exist in emergency situations • Problems and solutions associated with perforation, adverse hole conditions, and highpressure/high-temperature conditions • Environmental requirements that provide information associated with risk management and legislations. By following the documented processes disclosed in this paper, testing operations can be developed to avoid catastrophic events that could occur in the safest and most cost efficient manner.

Anchoring Malaysia’s first deepwater FPSO Dr. Samy Alhayari

SBM Offshore The 10 suction piles for Murphy Oil’s first deepwater FPSO, Kikeh, have been installed successfully in more than of 1,300 m (4,265 ft) in about five days using SBM/Solstad Normand Installer. SBM’s new “GAP: Gravity Actuated Pipe” was used for the first time to transfer the fluid from the spar to the FPSO MDFT (Malaysia Deep Floating Terminal), a joint venture of SBM Offshore and Malaysian MISC. Peak production is about 120,000 b/d of oil. The challenging Kikeh seabed conditions – with the presence of a telecom cable in the middle of one mooring bundle, excessive seabed slopes, and other complicated geology – have forced both parties to find a costeffective and appropriate anchoring solution of the FPSO. The FPSO mooring was originally designed with three-by-three legs but one of the bundles has to be increased to four legs instead of three to avoid the telecom cable by shorting the anchoring radius and increasing the chain size for that bundle. The FPSO is


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anchored to the seabed using 10 suction piles. The constructive cooperation between Murphy Oil and MDFT during the site surveys allowed adjustments to the anchoring radius and anchor points to a less risky area during the execution of the geophysical survey and prior to carry out the seabed testing and sampling boreholes. The FPSO is hooked-up to her ten legs and GAP connected between the spar and the FPSO. Subsea risers are being secured to the FPSO turret prior to start production. This is the first application of the suction pile technology offshore Malaysia. The coordination among SBM Offshore’s various departments during the design, fabrication, and installation key to this success.

component of a solution to this problem. New fiber-optic sensors are described. These sensors can obtain both discrete and distributed information regarding key structural integrity properties of the pipeline in addition to operating conditions such as pressure and temperature. Advances in installation methods and procedures means that these sensors can be deployed cost-effectively in new field applicatons as well as retro-fiitted to existing facilities. Case studies illustrating a number of applications are described.

Real-time condition monitoring of subsea pipelines

The presentation shows the benefits of wellhead-based subsea processing. It describes in detail how the standardized wellhead interface MARS (Multiple Application Re-injection System) has been deployed successfully on numerous subsea production optimization projects. In addition to discussing subsea multiphase pumping and metering applications, the presentation focuses on the recent successful deepwater well stimulation on Chevron Lobito Tomboco project in deepwater Angola. This project was completed in December 2009.

Jon Machin

Schlumberger Ensuring the structural integrity of subsea pipelines is a concern for many operators in the Asia/Pacific region. This presentation describes several ways in which real-time monitoring technology is emerging as an increasingly significant

Case studies on subsea production optimization Ian Donald

Cameron MARS Production Systems

The presentation will show how application of emerging technologies allows operators to maximize recovery using low-risk, low-cost tooling. Fluid intervention no longer requires full vertical well access for wireline or coiled tubing services. Chemicals now can be pumped into the well (or pipelines) in a controlled, safe manner without MODU facilities. There are a number of fluid intervention applications. They are used to protect the well against scale and hydrates; or to pump kill weight brine for well control; or to clean the lower completion or stimulating the reservoir to then tackle formation/production issues that evolve throughout the life of the well. The presentation also shows how to verify the principles of the unitized processing and the potential applicability to typical assets and provides additional technical information by updating actual projects, confirming the business case advantages of using this standardized interface, detailing how the technology can strategically to “future proof” assets , and presenting the HSE advantages of standardized tooling and procedures Lastly, the presentation provides details of current projects and system adoption by multiple vendors, suppliers, and operators to further standardize interfaces. 

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ARCTIC

Technology evolves for Arctic development

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ultiple offshore Arctic fields have been developed over the preceding three decades but there still is relatively little oil and gas being produced from the reportedly large estimated in-place reserves. This is because the unique Arctic environment presents technical challenges which often exceed those experienced with field developments in more temperate marine environments. Design, construction, and operation of facilities to support offshore Arctic exploration, field development, and production operations must address complex issues such as low temperatures, sea ice loadings,

Mike Paulin Duane DeGeer Glenn Lanan

INTECSEA Inc. seabed ice gouging, logistical support for facilities in remote locations, and oil spill contingency plans. The increasing number of offshore Arctic fields currently being safely and economically produced demonstrates that technical solutions are available to develop these valuable hydrocarbon reserves. Expanding international knowledge about Arctic conditions coupled with

improvements in material behavior, advances in analytical techniques, wider acceptance of progressive design philosophies, and implementation of reliable Arctic operational strategies enable additional offshore Arctic prospects to be developed. INTECSEA has summarized this growing body of international field development knowledge in the 2011 Arctic technology poster included in this month’s edition of Offshore magazine. Several individuals and organizations have provided input for this first survey of offshore Arctic technology challenges and solutions. Environmental conditions and field development requirements vary greatly within the Arctic and

Arctic polar view map of ice zones and existing oil and gas lease areas.



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on the right path

Looking North for new opportunities? Look to Newfoundland and Labrador, Canada. Consider us your landmark location for research and development in cold ocean technologies; unmatched expertise in harsh environment operations; and world-class supply and service for Arctic oil and gas exploration. Global industry has made us their North Atlantic base of operations for years. Find out why. The edge of the new frontier starts here. Make sure you’re on the right path.

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ARCTIC

for other cold regions, so the poster attempts to provide a balanced overview of the major technical challenges and available solutions. It presents a state-of-the-art summary of current geographical sea ice coverage, seasonal ice conditions, estimated hydrocarbon reserves in place, existing Arctic production facilities, field development strategies, concept selection alternatives, export solutions, and future challenges for Arctic and cold regions production. Local sea ice conditions such as seasonal first-year ice, multi-year ice and/or iceberg intrusions are a major differentiating factors for development schemes being used on existing and planned offshore fields in areas such as the Beaufort Sea, east coast of Canada, North Caspian Sea, and offshore Sakhalin Island. Jacket structures are suitable for relatively benign first-year sea ice environments such as in Cook Inlet and Bohai Bay. Gravel island structures can be used to resist multi-year sea ice loads in water depths up to approximately 15 m (50 ft) in areas such as the Beaufort Sea. Gravity-based structures (GBS) can be used in deeper water to resist multi-year ice and to limit iceberg loads. Example GBS applications include exploration structures used in the Beaufort Sea, and production structures offshore the east coast of Canada and Sakhalin Island. In deeper waters, FPSOs and other floating structure concepts

may be preferable with extensive ice management support and may allow emergency disconnect in the event of extreme ice loads. Another major differentiating factor is the availability of an export pipeline network versus the need for a dedicated tanker terminal and icebreaking shuttle tanker fleet. Subsea pipelines have been designed, constructed, and operated in arctic and subarctic regions. Challenges include burial for protection from seabed ice gouging and the limited time available for summer open water pipeline installation and trenching. Icebreaking shuttle tanker designs and year-round tanker loading terminals show significant advances in recent years. Environmental data collection programs covering multiple years, environmental restrictions, indigenous people’s use of the environment, and potential requirements to develop local support infrastructure also can impact the costs and schedules for future Arctic field developments. The world demand for oil and gas will continue to drive Arctic development, which will, in turn, drive development of solutions for some of the unique technical issues and logistical impediments to Arctic hydrocarbon recovery. As technology advances, other Arctic development concepts are becoming feasible. Subsea tiebacks are now in excess of 100 km (62 mi)

long, offering the possibility of Arctic subsea completions without a permanent host structure. Technical advancements in all-electric subsea control technology, full subsea separation and water re-injection, seafloor chemical storage and injection, and gas re-injection enable the concept of full subsea completions in the Arctic. Depending on reservoir conditions, some of these development options are currently at a high technology readiness level; some are even field-proven in non-Arctic regions. Research into improved leak detection systems continues to advance industry ability to detect potential leaks and supports the development of new systems for use in the Arctic. Arctic offshore design, subsea equipment technology, operating strategies, and understanding of Arctic environmental conditions will continue to advance and, as a result, the options available for Arctic and cold regions field development will grow. It is important to note that all aspects must be considered integrally in Arctic development plans. The design philosophy must provide a framework to logically incorporate the elements of Arctic development into one overall life-cycle system design. This, in turn, will optimize levels of risk and ensure consistent personnel and environmental safety over the lifetime of an Arctic field development. 

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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.

WHY ATTEND OFFSHORE WEST AFRICA? • A unique audience of the world’s leading executives, managers and engineers from major and independent E&P companies focusing on West Africa’s specific requirements • A world-class two-track technical conference program • An exhibition showcase of technology and capabilities to support improvements in African E&P operations • Expert opinions on the new issues, challenges and solutions associated with the expanding African exploration & production activity

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ARCTIC

Assessing the state of arctic technology development Today’s technologies make it possible to monitor facilities and systems in real time and remotely control sensitive equipment from shore G. Abdel Ghoneim, P.E., Ph.D.

Det Norske Veritas

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ooner or later, petroleum development of the Arctic Circle will take place. The technology exists today to safely and reliably develop the 25% of world oil and gas untapped reserves that exist there. The challenges associated with the design and operation of arctic exploration and production installations are many, and have been discussed exhaustively in the past. The goal here is to assess the current status of these challenges and to review the use of recent ice rules and standards in the design of fixed and floating arctic structures. The development of new DNV design guidelines on ice structure interaction is also discussed. That work will be completed in 2011 or early 2012. The project is based on the new ISO 19906 standard, and covers both fixed and floating installations. Finally, a number of past and recently proposed arctic development concepts, as well as some new untested ideas, are reviewed. It is noted that some concepts may not be feasible and may carry heavy risks, while others are quite feasible but may be prohibitively expensive. Balanced concepts are sought and presented.

Arctic structures There has been considerable experience gained through construction and operation of arctic climate structures in the US Cook Inlet, Canadian and US Beaufort Sea, Russian Sakhalin, and Canadian East Coast. There also has been considerable R&D work carried out on ice mechanics, ice structure interaction, and operational safety and environmental protection. The Exxon Valdez oil spill and the Deepwater Horizon/Macondo accident clearly demonstrate the significance of the human factor, even when the technology is thought to be “perfect.” Now attention is focused on preparedness and the development of ready-to-implement contingency plans in the event of such unexpected events. These efforts will also be applicable (with some adaptation) to arctic E&P developments. It is worth noting that in the 1970s it was rare to find ice and arctic specialists, whereas now it is not uncommon to see young engineers pursuing careers in arctic-related fields and completing higher education like M.Sc. and Ph.D. degrees from prominent Russian, U.S., Norwegian, Canadian, and other universities. The knowledge available today probably is adequate to design, construct, operate, and maintain an E&P structure in the Arctic Ocean on a year-round basis with safety levels that meet or exceed requirements currently adopted offshore in the Gulf of Mexico, the North Sea, the South China Sea, or West Africa. It is possible to demonstrate that such technology is reliable and effective. The cooperation and commitment of all stakeholders is necessary in order

Recently proposed arctic spar concepts.

to get arctic development on its way towards a safe, environmentally sensitive, and reliable future. The focus here is on arctic exploration and production structures. Technologies related to arctic shipping, pipeline/tanker transportation, ice management, and geotechnical issues are not addressed.

Arctic challenges Twenty arctic challenges are identified and tabulated (see “Arctic Challenges” table; Ghoneim, et al., 2010). They are given a significance ranking ranging from 1-4 (1 being most significant) with a status in percentage of where the technology is thought to be at present versus the desired situation. The estimates given are based on the judgment of the author. Experience with other offshore areas such as the Gulf of Mexico,



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ARCTIC

Earlier arctic concepts.

the North Sea, and West Africa where operations have been carried out successfully in harsh environments for many years and in deep waters indicate that the above level of competence for the Arctic is of similar level of reliability. Further assessment may be necessary to quantitatively make this comparison.

Arctic concepts Several concepts for arctic drilling and production systems are being promoted for application in the promising areas for future development. The concepts include drillships for year-round operation, jackups, production spars, gravity-based structures, FPSOs, and floating structures. A number of arctic spar concepts have been proposed by Sablok and Barras (2009) and Murray and Yang (2009). The spars are disconnectable upon encounter of ice features that exceed their design limitations and could be constructed of steel or concrete. An MMS (now Bureau of Ocean Energy Management, Regulation, and Enforcement or BOEMRE) research study by IMV Projects Atlantic Inc. (IMVPA, 2008) gives an extensive account of the technology status with regards to E&P options for application in cold regions such as the Beaufort Sea, the Chukchi Sea, and the Bering Sea. Bottom-founded fixed platforms, floaters, terminals, pipelines, and subsea options are discussed. In 1997, 2004, and 2005, three proposed arctic concepts and a more recent jackup type design were proposed for Sakhalin II by Gunningham, et al. (2008). A bottom-founded stepped type gravitybased structure in about 100 m (328 ft) of water was proposed for the Grand Banks offshore Newfoundland by Fitzpatrick, and Kennedy (1997). The second is an earlier spar concept proposed by Murray (2004); it has a disconnect feature allowing it to be towed away quickly upon threat of an approaching iceberg. The third is an arctic semi-rigid floater originally designed for Sakhalin Island by CKJ Engineering (2005) for 80 to 500 m (262 to 1,640 ft) water depth. Not much detail is given for the arctic jackup concept in Gunningham, et. al. (2008). It is only stated that the concept is under investigation. A US patent application for an arctic year-round drilling jackup design by Brinkman and Davenport (2010) has also been submitted. The gravity-based structures are suited for up to 100 m water depth in regions with multiyear (MY) ice and to 150 m (492 ft) in first year (FY) ice, respectively. Jacket and jackup type platforms are feasible to water depth of about 60 m (196 ft) in regions like Cook Inlet and the Bering Sea, but may not be suitable for the Beaufort or Chukchi seas. It is possible to construct ice or gravel islands for up to about 12 m (39 ft) water depth. Gravel islands may not be suited for the Chukchi Sea’s more dynamic conditions compared to the Beaufort Sea. The IMVPA (2008) study also states that floating structures are not feasible for the Beaufort, Chukchi, or North Bering seas, even with ice management. Therefore, only Bering Sea-like conditions may be tolerated year-round by floaters that have the capability to disconnect in severe conditions. Subsea systems are feasible in re-

gions with sufficient water depth to avoid ice interaction or with provision of glory holes to house the system with tiebacks of 170 km (105 mi) for gas and 65 km (40 mi) for oil production. The choice of an appropriate exploration or production system does not only depend on water depth and ice conditions, but also on the ice management and disconnect capabilities commensurate with the arctic region under consideration. The risks associated with the operation and the consequences of failures have to be quantified and understood. All the concepts presented above are (in this author’s opinion) feasible and balanced with regards to cost and risk management during design, construction, installation, operation, and decommissioning. Additional studies are however recommended to address site specific conditions and logistics.

Design philosophy Two methods normally are employed in design; namely, the limit states load and resistance factor design (LRFD) and the working or allowable stress design (WSD or ASD). The differences between the two methods depend on the magnitude of the environmental load relative to the permanent load. The allowable stresses are increased by a third when extreme loads are applied. The AISC, 2005 13th Edition Steel Construction Manual has discontinued this practice by only allowing the one-third increase on the portion of the stress caused by the variable and environmental loads. No increase is allowed for the permanent or dead-load effects. Notably, the Manual now includes both the ASD and the LRFD design methods in the same document. The comparison made here shows that as the environmental loads increase relative to the gravity loads, the LRFD methodology becomes more appropriate with regards to the safety factor. The a) and b) notations refer to the operating and extreme load conditions, respectively. It is therefore recommended that the design of arctic structures be based on the LRFD method rather than the customary WSD

Schematic of LRFD vs. WSD methods.



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ARCTIC

employed so far in the design of US Gulf of Mexico offshore structures and adopted by most API specs and RPs.

ICESTRUCT JIP This DNV joint industry project is studying the effects of ice on arctic offshore structures. It aims to present a common and documented approach to achieve acceptable safety levels for offshore structure designs in cold climate regions, by adhering to the normative provision of the ISO 19906 standard issued in December 2010, and by supplementing it through the provision of practical design recommendations and case studies. In close dialogue with the ISO Working Group responsible for ISO19906, DNV is developing a companion document to the ISO standard in the form of a Technical Guideline (which may be turned into a DNV Recommended Practice in the near future). The Guideline should be considered a supplement to the Informative provisions of ISO19906, providing practical design recommendations, limitations, and case studies (Cammaert and Horn, 2009). An initial gap analysis highlighted areas where additional research was warranted. One of the areas to be covered in the project guideline is ice effects on floating structures, which has not been addressed in detail in the ISO 19906. In particular, the scope of the guideline is to provide practical guidance on key issues related to the following topics: • Design methodology, particularly relating to safety philosophy and probabilistic design • Characteristics, properties, and conditions for sea ice and icebergs in selected areas • Ice action scenarios and load prediction algorithms for fixed and floating structures • Discussion of structure response for key design issues • Case studies for fixed and floating structures. The JIP participants include Barlindhaug, Daewoo, ENI, Hyundai, Olav Olsen, Keppel, Repsol, SBM, Shell, Statoil, Transocean, and the BOEMRE. The project is anticipated to be completed by 2012.

Conclusions When thinking about the present status of arctic technology, thought must be given to whether there is sufficient confidence to support oil and gas exploration and production development in arctic regions. As always, this is a balance between risks and benefits for all stakeholders. The challenges are numerous and significant, but the associated risks are more manageable now than ever. Today’s technology makes it possible to monitor the condition of the arctic facility and its associated systems in real time and remotely control sensitive equipment from shore. Even with the considerable uncertainty associated with ice loading and the design criteria, it is possible to mitigate these issues using probabilistic methods and to incorporate a reliable monitoring system and innovative designs that allow ductile structural behavior and fail-safe arrangement. Depending on the water depth and the ice conditions, many arctic designs have been proven in the past, and that experience is going to be beneficial in designing new structures for deeper waters and more severe ice conditions. The recently issued ISO 19906 standard does cover a very wide scope and will be invaluable to the designers and operators of arctic structures. The document still lacks detail for ice load calculations especially for floating systems. Also, the requirement that ice structure interaction should be performed using probabilistic methods is too general and an alternative deterministic method should be defined. However, the designers will be relying on class societies for more specific guidance. DNV is going to produce such guidance in

mid-2012 after work is completed on the JIP ICESTRUCT. The definition of local ice pressure dependence on the contact area has been improved in the new ISO standard. However, due to the sensitivity of the structural weight to the local pressure and hence the feasibility of the design, it is important to optimize the design by employing plastic and nonlinear design methods. The experience from existing arctic shipping, exploration, and production has been successful to date. There is no doubt that existing technology can produce year-round drilling and production systems in all the contemplated arctic regions efficiently, with the same or better reliability than currently experienced in field developments in deepwater and harsh environments. 

Acknowledgment Based on a paper presented at the Deep Offshore Technology International Conference and Exhibition held in Amsterdam, Nov. 30 through Dec. 2, 2010.

References American Petroleum Institute, “Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms,” API RP 2A, 1st through 21st Editions, 1969-2005. American Petroleum Institute, “Recommended Practice for Planning, Designing and Constructing Structures and Pipelines for Arctic Conditions,” API RP 2N, 2nd Edition, December 1, 1995. Brinkmann, C. and Davenport, G, “Mobile Year-Round Arctic Drilling System,” Pub. No. US 2010/0221069 A1, September 2, 2010. Cammaert, A.B. and Horn, A.M. “New DNV Recommended Practice for Ice Effects on Arctic Offshore Structures,” POAC09-50, Lulea, Sweden. Canadian Standards Association (CSA), “Design, Construction and Installation of Fixed Offshore Structures – General requirements, design criteria, the environment, and loads”, CAN/CSA-S471-04, February 2004. Det Norske Veritas (DNV), ICESTRUCT JIP, “Ice Effects on Arctic Offshore Structures,” October 1st, 2009. Det Norske Veritas (DNV), Rules for Classification of Ships, PART 5 CHAPTER 1, “Ships for Navigation in Ice,” July 2010. DNV Offshore Standard OS-C201, “Structural Design of Offshore Units (WSD Method),” October 2008. DNV Offshore Standard OS-C101, “Design of Offshore Steel Structures General (LRFD Method)”, October 2008. DNV Recommended Practice RP-A203 “Qualification Procedures for New Technology,” September 2001. Gautier, D.L., Bird, K.J., Charpentier, R.R., Grantz, Arthur, Houseknecht, D.H., Klett, T.R., Moore, T.E., Pitman, J. K., Schenk, C.J., Schuenemeyer, J.H., Sørensen, Kai, Tennyson, M.E., Valin, Z.C., and Wandrey, C.J. 2009, “Assessment of Undiscovered Oil and Gas in the Arctic,” Science v. 324, p.1175-1179. Ghoneim, G. A., “Recent Developments in Offshore Codes, Rules and Regulations for Deepwater and Arctic E&P Systems,” ISOPE-CCC-01, Vancouver, Canada, July 6-10, 2008. Ghoneim, G. A., and Por-Feng Peng, “Application of Recent Ice Class Requirements for Arctic E&P Offshore Structures,” ISOPE-CC-01, Osaka, Japan, June 21-26, 2009. Ghoneim, G. A., Cammaert, A. B. (Gus), and Morten Mejlænder-Larsen “Arctic Challenges – A Treatise of Past and Recent Developments,” ICETECH10-183USA, Anchorage, AK, September 20-23, 2010. Gunningham, M., Varley, C., and Cagienard, P., “The Integrated Use of New Technology in the Development of the Sakhalin II Project,” SPE 114805, Moscow, Russia, 28-30 October, 2008. IMV Projects Atlantic, “Arctic Offshore Technology Assessment of Exploration and Production Options for Cold Regions of the US Outer Continental Shelf,” United States Department of the Interior Minerals Management Service, Technical Report No. TR-001, January 31, 2008. International Standards Organization, ISO/FDIS 19901-1:2005(E) “Metocean design and operating considerations,” voting terminated 2005-09-28. International Standards Organization, ISO/FDIS 19906 “Arctic Offshore Structures,” ISO TC 67/SC 7, 2010. Murray, J. J. and Yang, C. K., “A Comparison of Spar and Single Column Floater in an Arctic Environment,” OTC 19797, 4-7 May, 2009. Sablok, A. and S. Barras, “The Internationalization of the Spar Platform,” OTC 20234, 4-7 May, 2009. U.S. Geological Survey, Circum-Arctic Resource Appraisal (north of the Arctic Circle) Assessment Units GIS Data, 2009. U.S. Geological Survey, “U. S. Geological Survey Oil and Gas Resources Assessment of the Russian Arctic”, DOE Award No. DE-A126-05NT15538, Final Report submitted to the Department of Energy National Energy Technology Laboratory, July 2010. www.offshore-mag.com • February 2011 Offshore 69


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SSTB PREVIEW

Subsea Tieback Forum returns to San Antonio Growing focus on quality, safety and economics of subsea tiebacks

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he annual Subsea Tieback (SSTB) Forum & Exhibition returns to San Antonio Feb. 22-24, 2011, at the Henry B. Gonzales Convention Center. More than 3,000 attendees and 150 exhibitors are expected at this year’s conference. This year’s theme, “The Pressure Is On,” reflects the growing focus on improving the quality, safety, and economics of the subsea tieback industry. The conference Advisory Board once again has put together a program of two days of key presentations by industry leaders. As in the past, only by participating in this conference will attendees be able to receive its benefits, as proceedings will not be published and no media is allowed in the conference area. Subsea Tieback is presented as a closed forum to encourage free and open discussion for the most benefit of all attendees.

Key Elements Seminar Tuesday, Feb. 22, will feature a one-day seminar sponsored by Aker Solutions on “Key Elements of Subsea Tiebacks (SURF)” to be conducted under the auspices of the Society of Underwater Technology. There is a separate cost to attend this seminar. The daylong event has four sessions plus an update on intelligent well interface standards. Session 1 schedules Bill Donlon, BHP Billiton, to set the scene with a deepwater activity forecast, facts and figures regarding tiebacks, issues and key components, as well as sample layouts. He will be followed by Tom Kelly, FMC Technologies, who will discuss system considerations, subsea completions, control systems, manifolds and tie-ins, and installation and workovers. In Session 3, umbilicals, risers, and flowlines will be the topics for Chuck Horn of Technip. He will be followed by Cory Loegering of Mariner Energy to discuss production handling agreements. After that, Don Schlater, SUT, will talk about intelligent well interface standards and is scheduled to end with questions and answers. The Opening Plenary Session, starting at 8 a.m. on Wednesday, Feb. 23, will begin with a welcome and introduction by Eldon Ball, Conference Director, US Offshore Group, and Senior Editor, Technology & Economics, for Offshore magazine. He will be followed by Richard Case, W&T Offshore and Chairman of this year’s Subsea Tieback Forum. Stephen L. Schroeder, Senior Vice Presi-

The annual Subsea Tieback Forum & Exhibition returns to San Antonio Feb. 22-24, 2011, at the Henry B. Gonzales Convention Center

dent and COO–W&T Offshore, Inc., will deliver the keynote presentation. Schroeder joined W&T Offshore in 1998 as a Staff Reservoir Engineer. A leader in W&T’s growth to the public company it is today, he held positions of increasing responsibility, including Production Manager and Vice President of Production before becoming the COO in July 2006. Prior to joining W&T, Schroeder was with Exxon USA for 12 years, serving successively as an Offshore Division reservoir engineer; financial analyst conducting deepwater profitability studies; team leader evaluating company reserves, gas plants and operating expenses; and an acquisition engineer responsible for acquisition and divestiture evaluations.

A few session highlights Session 1, Artificial Lift: Testing & Qualification, begins with a presentation on “Full Scale Testing of a Subsea Boosting System at Prototype Facility” by Charles Deuel & Jim Hale of Shell. The presentation will discuss the challenges and learnings of testing a full scale subsea separation and boosting system prior to use on Parque Das Conchas and Perdido. Charles Deuel is a senior process and flow assurance engineer at Shell Upstream Major Projects – Americas. He has worked on projects such as Llano, Habanero, Ursa Princess waterflood, and Parque das Conchas. Jim Hale has 29 years of deepwater experience in the oil and gas industry. He has spent the last 12 years with Shell and the previous 17 with Brown & Root. Hale is currently Shell’s deepwater Gulf of Mexico surface lead for opportunities in Selectphase and earlier.

Their presentation will be followed by Chris McMillan of Chevron, who will speak on “Applying New Pump Technology on the Jack & St. Malo Project.” He will be followed by Alexander Hague of Petrobras America, speaking on the “Petrobras Cascade and Chinook Pump System Design and Development.” The presentation will cover the early concept of this pump system design through the detailed development, qualification and system integration testing. Hague has worked for 13 years in the oilfield industry after graduating with a Mechanical Engineering Degree from the University of Houston. Currently he is working as the Pump Systems Lead Engineer for the Petrobras Cascade and Chinook Field Development. Session 2, Project Learnings, will begin with a presentation on “Field Performance of a Caisson/ESP Subsea Separation and Boosting System” by Wade Schoppa of Shell. It will include an overview of the subsea separation and boosting system at Parque das Conchas (BC10), including assessment of subsea processing performance with field data. Dr. Wade Schoppa is a senior staff flow assurance engineer at Shell Upstream Major Projects-Americas. He serves as the flow assurance technical authority for deepwater projects in Shell-Americas, including Europa, Angus, Nakika, Parque das Conchas (BC-10), and Perdido. His presentation will be followed by a discussion of “Pyreness Development & MPFM Remediation Effort,” presented by Karl Schnakenburg, of BHP Billiton. He will be followed by Jim Burk, of BP America, who will present on “Subsea Challenges – Thunder Horse HP/HT Systems – Umbilicals, Flowlines, Manifolds Risers, and General Subsea Equipment.” The presentation will give an overview of the material challenges for delivery of a HPHT subsea system in ~ 5,000 ft water depths with a 15,000 psi rate wellhead and tree system. To successfully deliver the system equipment, many subsea components required materials that needed to perform on the edge of current technologies. The 8-year effort to develop and deliver these materials will be reviewed and key points will be discussed to enable this subsea leading materials technology. The conference ends with the Recognition Awards & Chairman’s Closing Remarks by Conference Chairman Richard Case. For more of the latest in information and schedule updates, or to register for the event, go online to http://www.subseatiebackforum.com. 



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GEOLOGY & GEOPHYSICS

Atlantis project proves viability of OBN in 4D Project team traces steps to success for seabed seismic repeatability

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he world’s first ocean bottom seismic node-on-node time-lapse (4D) monitor survey was acquired in 2009 at the Atlantis field in the Gulf of Mexico. Field operations went as planned safely and the equipment worked as expected. The combined source and receiver positioning repeatability was achieved to within 30 m (98 ft), second only to permanent installations. Processing advances made during the project will provide lasting benefits for the static image and achieved best-in-class 4D noise levels. These results show that nodes are suitable for highly repeatable time-lapse seismic programs. Atlantis sits 150 mi (241 km) into the GoM off the Louisiana coast in the southern Green Canyon area. This prolific trend is home to other large fields such as Mad Dog, Shenzi, K2, Timon, and Neptune. Atlantis began production in October 2007 from Miocene turbidite reservoirs 17,000 ft (5,182 m) below sea level, 7,000 ft (2,134 m) of which is water. The desire for repeatable time-lapse seismic in deepwater combined with the challenges of significant surface and subsea installations made Atlantis ideal for ocean bottom node (OBN) technology. The baseline survey, acquired in 2005-2006, was the world’s first large-scale deepwater OBS survey to use autonomous nodes (Beaudoin and Ross, 2007). The primary baseline objective was a consistent, high-quality image of the subsalt portion of the reservoir to guide appraisal work. One year after production began, BP put in place a team dedicated to executing the design, acquisition, processing, and interpretation of a time-lapse survey.

Method The project team consisted of a project manager, seismic interpreters, seismic acquisition specialists, safety management personnel, ROV experts, marine advisors, and seismic processors. The team first set about to design the acquisition and to plan the processing flow.

Node locations in Atlantis baseline and monitor surveys.

Micah Reasnor Gerald Beaudoin Michael Pfister Imtiaz Ahmed Stan Davis Mark Roberts John Howie

BP America Inc. Graham Openshaw

TecPM Andrew Longo

Clover Global Solutions The baseline survey consisted of 1,628 nodes. However, the producing area of the field only comprised a small portion of the baseline survey image area. The design sub-team decomposed the original survey into individual single shot migrations and then created stacked images of progressively smaller surveys. Extracting coherency and amplitude maps at the reservoir level on each of these sub-images and comparing section views allowed the team to pare the node count down to an optimal 500 nodes. This reduced the node area from 247 sq km (95 sq mi) to 80 sq km (31 sq mi). Analysis of offset contributions to image quality led to a reduction of the minimum far inline offsets from 8 km (5 mi) to 6 km (3¾ mi). These two decisions decreased source area and cost by about 40% compared to

the base line survey. The priority for the processing team after receiving the data would be to QC data. This would need to compare the monitor survey to the base line survey on a shot-by-shot and receiver-by-receiver basis to ensure that the exact same traces were repeated and then carried into the time-lapse imaging flow. To reduce processing cycle time, these processes and their resultant QC displays were automated and tested on real datasets. Next, the pre-processing flow was developed by incorporating BP’s best practice imaging flows obtained from years of experience in 4D operations elsewhere. These flows were modified to account for the deepwater, partial subsalt nature of the Atlantis project, and then tested by processing the baseline survey through the entire flow. Later, pre-acquisition field trial data was used as a second test data set, which allowed the team to vet the time-lapse components of the processing flow. Operations planning was in parallel to the survey design and processing preparations. An initial joint risk assessment meeting with the acquisition contractor, Seabird Exploration, set the stage for a joint effort to prepare the field operations. The preparations spanned several months and included redesigning some of the field equipment, creating new procedures, training, and drafting of detailed operation plans. The result was a smooth field operation in which the plan was executed as expected, the equipment worked as planned, there was no impact on Atlantis production, and most importantly the project was concluded safely. The operation completed within the planned time frame and 98.8% of nodes returned complete datasets after one month on the seafloor. This node failure rate is on par with results from previous node surveys in the GoM (Smit et al., 2008, Beaudoin and Ross, 2007). This success can be attributed to having the right expertise, taking the time to plan, and the willingness of both parties to learn from each other which resulted in needed changes. The geophysical challenge in planning a time-lapse survey is accurate repetition of both source and receiver signatures and positions. Autonomous



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OBS nodes present, at least initially, a greater repeatability challenge for signature. There is great variety amongst the various node systems. The baseline survey node (a Fairfield Z3000) is gravitationally coupled to the seafloor, while the sensor of the monitor survey node (a SeaBird CASE Abyss) is planted into the soil. Fortunately, the survey design team could rely on the results of two Atlantis sea trials in 2004 (Openshaw and Beaudoin, 2006) that evaluated both styles of autonomous nodes. These results indicated that, within the range of Atlantis soil conditions and within the required seismic bandwidth, both systems would record seismic data of sufficiently similar quality to support a time-lapse monitor survey. Any minor differences could be accommodated in the time-lapse processing flow. Achieving node position repeatability in the Atlantis area is challenging, with depths ranging from 1,300 m (4,265 ft) to 2,200 m (7,218 ft) in very rugged terrain. Position accuracy was achieved using the Kongsberg HAIN (Hydroacoustic Aided Inertial Navigation) system. This uses USBL (Ultra Short Baseline) positioning but stabilizes the short-term position noise using both an inertial guidance platform and a Doppler Velocity Log. This approach was intended primarily to produce rapid position convergence to allow the ROV to move quickly to a target without jitter, but it also appeared to improve overall positioning. The long tail of the error distribution is caused by a deliberate choice to favor external sensor coupling over closer geometric repeatability. In a few locations, ROV pilots reported difficulty in fully planting the external sensor. The ROV pilots were given the latitude to search for softer ground within a 20 m (65½ ft) radius of the target location. The source signature was repeated by designing the monitor survey source array to match the baseline array. However, the team did elect to tow the monitor source array at a depth of 12 m (39 ft) compared to 15 m (49 ft) for the baseline survey to gain higher frequency content. This change did not impact repeatability because there were only minor changes to the frequency spectrum within the range of concern. The advantage of this design is that a new static image of the extra-salt portion of the field could be made with higher frequency content than the baseline survey, which was designed for a lower frequency subsalt image. Any subsequent time-lapse surveys also could take advantage of this. As mentioned, the team also changed the minimum offset requirement, reducing it from 8 km to 6 km. To meet this requirement, careful coordination is required between ROV and source vessel during the operation. The source vessel must operate at offset greater than 6 km

(Above) Baseline survey – node deployed on the Sigsbee Escarpment. (Below) Monitor survey – node deployed 3.4 m from baseline location. White arrow indicates external sensor.

from the nearest node being placed on the seafloor. Conversely the ROV cannot remove a node from the seafloor until the source moves off by that minimum offset. In processing, offsets greater than 6 km were removed from the baseline survey. To achieve source positioning accuracy during acquisition, the starboard gun array was steered to match the baseline shot positions achieving a high percentage of shots within 10 m (33 ft) of the baseline positions. Inclusion of the un-steered port shots gives a maximum source position error of 25 m (82 ft) despite considerable loop current activity. The combined source and receiver repeatability is on the order of 30 m (98 ft). This remarkable geometric repeatability, approaching that of permanent arrays, provides a new option for acquiring highly repeatable timelapse surveys in producing fields. The final shipment of node data arrived in BP’s Houston seismic processing center one week following acquisition. The team began to implement the planned flow and produced an initial image within just seven weeks. However, the initial images exhibited a high degree of time-lapse noise which is observable in the overburden section of the monitor minus base difference section. This noise is caused by variability in the spectrum due to local seabed conditions, subsalt-generated noise, and subtle velocity errors causing non-flat gathers. The team began to reduce this noise through

a series of small experiments. The first experiment revisited the spectrum matching filters. In the initial flow a single, global filter was chosen by analyzing the near offset direct arrivals. An alternative method was tested in which a matching filter was derived for each node and the filter window was lengthened to capture lower frequencies. This proved superior. Second, the subsalt noise was addressed. A salt transmission attenuating migration was created which attenuated any energy passing through the salt body which encroaches from the north in the overburden. The producing area image primarily is extra-salt so this had no negative impact on the target image but did remove the subsalt-generated noise. A final experiment enhanced the structural image. Post migration common image gathers were created from the wave equation migration. A trim statics approach flattened the gathers before stacking. This had a significant impact on amplitude fidelity, image quality, and matching between base and monitor. The result of this new processing flow can be seen by comparing the original monitor minus base difference section to the new difference section. Time-lapse noise measurements taken within the overburden, in terms of the Calibrated Difference in Reflectivity (CDR, Dyce et al., 2004), are among the lowest in BP’s experience, even compared to permanent installation surveys. A disciplined project management team, focused on risk identification and mitigation, and with broad technical expertise allowed BP to successfully acquire of the world’s first node-on-node time-lapse survey. This project has demonstrated that ROV-deployed nodes can reliably conduct highly repeatable 4D surveys. Node reliability approached 99%, and over 90% of nodes were delivered to within 5 m (16 ft) of seafloor locations that had been occupied over three years before. Source repeatability was achieved to within 25 m (82 ft). Final time-lapse images yielded a CDR noise level measurement among the best in the BP portfolio. This success marks the addition of another tool to BP’s growing portfolio of surveillance technologies. 

Acknowledgments The authors thank BP and BHP Billiton for permission to publish this article and for their support of the project. Collaboration with the onshore and offshore staff of SeaBird Exploration contributed to the success of this first node-on-node, time-lapse survey. In addition to the authors, team members included Georgiy Astvatsaturov, Jeff Collins, Jonathan Davis, William Davison, Ray Harrison, Michael Mervin, Randy Read, Scot Rudolph, Werner Schueller, Kenny Gullette, and Hans Sugianto. Based on a paper presented at the SEG 2010 Conference held Oct. 2-5, in Keystone, Colorado.



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Subsea gas hydrates offer huge deepwater energy potential Ray Boswell

Gas Hydrate R&D Programs U.S. Department of Energy National Energy Technology Laboratory

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esearch results over the past decade, including drilling and coring, experimental studies, and numerical simulations, are clarifying the resource potential of gas hydrates. Key to recent advances is the recognition that gas hydrate is not something exotic, requiring fundamentally new technologies. Instead, gas hydrate is best thought of as the shallow extension of existing deepwater petroleum systems, fully amenable to exploration and potential production using the same tools and concepts as traditional hydrocarbon resources. The conduct of the impending field sampling and production tests will be the next major step in the evaluation of this potential resource. Methane hydrate, a solid compound formed from the inclusion of methane molecules within an open lattice of water molecules, is familiar to those who work in deepwater oil and gas exploration and production. The formation of solid gas hydrate plugs within drilling and production tubulars and equipment is a wellknown hazard. However, this article is not about hydrate that forms as a consequence of offshore operations, but instead about issues related to naturally occurring hydrate that forms and evolves gradually over geologic time within the shallow sediments of deepwater continental slopes and shelves. Gas hydrates require an unusual combination of relatively cold temperatures and relatively high pressures to become stable. In the early 1960s, scientists in Russia noted that methane and water co-exist widely in areas of the Siberian permafrost, and speculated that gas hydrate might be responsible for some unusual reservoir behavior observed in shallow western Siberian gas reservoirs.1 In the early 1970s, gas hydrates were inferred to occur in arctic Alaska and Canada as well, and speculation began that gas hydrate could exist in the marine environment in significant volumes. The physical occurrence of gas hydrate was confirmed by scientific drilling expeditions in late 1970s and early 1980s that recovered natural gas hydrate samples from the continental shelves of North and Central America. By the

Logging-while-drilling data acquired during the 2009 Gulf of Mexico Gas Hydrates JIP Leg II Expedition in Walker Ridge block 313. The data show two units (green) with low gamma ray, high resistivity, and high compressional velocity consistent with gas hydrate saturations between 50% and 90% of pore space. (Courtesy JIP Leg II Science Team).

mid 1990s, there was general consensus that gas hydrates in nature likely housed as much organic carbon as all known oil, gas, and coal deposits combined.2 The pressure temperature requirements for gas hydrates stability restrict marine gas hydrates to water depths greater than ~300 to 500 m (984-1,640 ft) depending on water-bottom temperatures. Seaward of this limit, the zone of potential gas hydrate occurrence (the gas hydrate stability zone, or GHSZ) generally increases with water depth, a trend locally complicated by variations in pore-water salinity, geothermal gradients, and gas geochemistry. However, even in very deepwater, gas hydrate generally is restricted to the upper 1,000 m (3,281 ft) or so of sediment. Gas hydrate occurrence also is thought to be most com-

mon on the organic-rich continental shelves, slopes, and rises where the supply of biogenic methane is greatest.

Potential drilling hazard Since the earliest stages of deepwater drilling, industry practice has been to include inferred gas hydrates deposits along with shallow gas, water flows, and potentially unstable seafloor, as the primary potential shallow hazards to be avoided. The gas hydrate-related hazard derives from the potential release of gas and water in response to drilling-imparted pressure, salinity, and temperature changes. In 2000, in response to accelerating industry activity in the deepwater, a joint industry project (JIP) lead by Chevron entered into a cooperative agreement with the Department



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WEBCAST | 02.24.11

We’ll get straight to the point! Meeting the Challenges of Arctic Development Sign up today for Offshore’s free informative webcast. Solutions and guidelines outlined for safe and efficient offshore operations in the severe Arctic environment. The webcast will showcase the following Arctic region experts : Dr. Shawn Kenny, Wood Group Chair in Arctic and Harsh Environments Engineering and Associate Professor at Memorial University in St. John’s, Newfoundland and Labrador G. Abdel Ghoneim, PE, PhD, Det Norske Veritas

Thursday

February 24th 9:00am (CST)

Joe Gagliardi, Arctic Solutions and Technology Director, ION Geophysical Corporation

Webcast Overview 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 will present an overview of practical engineering solutions that will allow oil and gas operators to safely and efficiently work in Arctic offshore environments.

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Dr. Kenny will be joined by G. Abdel Ghoneim, 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. Joe Gagliardi will discuss the challenges of acquiring and processing seismic data in Arctic environments.

Listen to and participate in this live webcast by registering at: www.offshore-mag.com (webcast section)

Sponsorships are still available. Contact your sales representative today. Previous Page | Contents | Zoom in | Zoom out | Front Cover | Search Issue | Next Page

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of Energy to explore issues related to naturally occurring gas hydrates in the GoM. Despite drilling thousands of wells through the GHSZ in the GoM, field data on gas hydrate was scarce owing both to industry’s active and successful avoidance of gas hydrates, and to the general policy of rapid tophole drilling with minimal data collection designed to get the shallow section behind casing as quickly as feasible.3 A longer term gas hydrate-related hazard is the localized and progressive dissociation of gas hydrate that could result from sustained exposure to wellbores transmitting hot fluids from deeper reservoirs through gas-hydratebearing sediment. This concern was the primary impetus for a major field program conducted by Shell and partners in 2005 in advance of development at the Gumusut-Kakap field offshore Malaysia. Numerical simulations conducted with those data indicated a risk of well-casing integrity loss over planned 30-year production timelines due to weakened physical strength in hydrate-bearing zones.4

A potential resource The enormous in-place resources attributed to gas hydrates are a major impetus for the study of their production potential. At present, these volumes remain poorly constrained; however, it is likely that the global resource is measured in the hundreds of thousands of Tcfg.5 However, in-place volumes provide little insight into the issue of resource potential. Field data, supported by experimental and numerical simulation studies, confirm that the richest (in terms of gas hydrate concentration) deposits form in permeable (sand-dominated) sediments and that such deposits will release gas to wellbores under known production scenarios.6 The ability to produce gas from sand-hosted gas hydrate via depressurization using existing well-based drilling and production technologies was confirmed by field tests in Alaska (2007)7 and in northern Canada in 2007-2008.8 A 2008 assessment of gas hydrates on the Alaska North Slope9 conducted by the U.S. Geological Survey (USGS) indicated that depressurization-based production should result in recovery factors up to 85%, a conclusion supported by numerical simulation.6 Early concepts viewed marine gas hydrate production as limited to either small, massive seafloor mounds, or to large but low-concentration deepwater deposits in unconsolidated, lowpermeability muds. However, drilling in the Nankai trough offshore Japan’s southeast coast in 1999 and again in 2004 encountered thick sequences of turbiditic sands with gas hydrate saturations ranging up to 68% of pore space.10 Gas hydrate later was found in Oligocene Frio sand in Alaminos Canyon 818 in the GoM in 2004.11 In 2008, the Bureau of Ocean Energy Manage-

ment, Regulation and Enforcement (BOEMRE) released an assessment12 that indicated a mean probabilistic estimate of more than 21,000 Tcfg in-place in hydrate form in the northern Gulf of Mexico with ~6,700 Tcfg occurring at high saturations in sand reservoirs. In 2009, a second program conducted by the Chevron-led JIP, in collaboration with DOE and USGS, drilled three sites in which hydrate prospects had been defined using the same concepts and tools, such as integrated geological geophysical facies analysis and inversion of seismic data for saturation estimation, which guide conventional hydrocarbon exploration. This expedition discovered gas hydrates at high saturations in sands at depths ranging from 1,400 to 2,500 ft (427 to 762 m) below the sea floor in four of seven wells drilled.13 A follow-on expedition to collect, preserve, and analyze core samples at in situ pressures is in planning with a target date of 2012. These recent positive findings suggest that a realistic global range for potential recoverable resources of gas hydrate from marine sands could well be on the order of 10,000 Tcf.5 The recent discovery of a new class of gas hydrates, characterized by thick sections of deformed marine muds characterized by dense swarms of gas hydrate veins,14 may provide additional resource potential. Nonetheless, the potential commercial viability of these resources is not clear. In the most favorable case, gas hydrate-bearing sands, production will face technical challenges, and while thought to be possible with proven technologies, they would add significant cost burdens to potential marine development projects.15 Nonetheless, global drivers for energy supply and increased energy security will continue to spur gas hydrate R&D.

Extended tests planned Key to enabling gas hydrate production will be a full understanding of the realities of reservoir behavior, the potential production profiles that are obtainable, and the range of environmental implications of field development. A series of extended duration and closely monitored field tests are needed to advance these issues, and are in planning. Japan has recently announced the intention to conduct a monitored field production test offshore Japan as early as 2012,16 and the US DOE and USGS are continuing to work with Alaska North Slope operators to begin a field testing and monitoring program as early as 2011. Environmental impact monitoring of production tests would include assessment of geomechanical changes in the reservoir and the overlying seals as a result of production. Reservoir compaction could lead to ground or sea-floor subsidence or instability, whereas loss of seal integrity could enable the release of dissociated gas to the overlying sediments.

Work during the 2009 JIP field expedition.

Mitigating these risks is the fact that gas released from a buried hydrate deposit will be moving deeper into phase stability envelope (with potential for hydrate re-formation and self-sealing). Also the most likely targets for production will be those that are most deeplyburied, as deep burial positively impacts key production issues such as proximity to favorable phase stability boundaries and higher sediment strength.  References 1. T. Collett, A. Johnson, C. Knapp, and R. Boswell, AAPG Mem 89, 2009. Ch. 1. 2. K. Kvenvolden, Chem Geol., 1988, 71, 41-51. 3. R. Birchwood, S. Noeth, E. Jones, NETL Fire in the Ice, Winter 2008, 1-4. 4. C. Hadley, D. Peters, A. Vaughan, D. Bean, Proc. Int’l Petroleum Technology Conference, 2008, IPTC-12554. 5. R. Boswell, T. Collett, En. Environ. Sci., 2010, doi:10.1039/c0ee00203h 6. G. Moridis, T. Collett, R. Boswell, M. Kurihara, M. Reagan, E. Sloan, C. Koh, SPE Reservoir Evaluation and Engineering, 2009, 745-771 . 7. R. Boswell, T. Collett, B. Anderson, and R. Hunter, eds. Jour. Mar. Pet. Geol. 2010, 27 (10) 8. K. Yamamoto and S. Dallimore, NETL Fire in the Ice, 2008. Winter, 1-5. 9. T. Collett, W. Agena, M. Lee, M. Zyrianova, K. Bird, R. Charpentier, D. Houseknecht, T. Klett, R. Pollastro, C. Shenk, USGS Fact-Sheet 2008-3073. 2008. 4 pp. 10. Y. Tsujii, T. Fujii, M. Hayashi, R. Kitamura, M. Nakamizu, K. Ohbi, T. Saeki, K. Yamamoto, T. Namikawa, T. Inamori, N. Oikawa, S. Shimizu, M. Kawasaki, S. Nagakubo, J. Matsushima, K. Ochiai, T. Okui, AAPG Mem 89, 2009. Ch 12. 11. R. Boswell, D. Shelander, M. Lee, T. Latham, T. Collett, G. Guerin, G. Moridis, M. Reagan, D. Goldberg, J. Mar. Pet. Geol., 2009, 26 1499-1512. 12. M. Frye, MMS Report, 2008-004. 2008. 136 pp. 13. R. Boswell, T. Collett, D. McConnell, M. Frye, W. Shedd, S. Mrozewski, G. Guerin, A. Cook, D. Shelander, J. Dai, P. Godfriaux, R. Dufrene, E. Jones, R. Roy, Proc. Offshore Technology Conference, 2010. OTC-20560. 14. T. Collett, M. Riedel, J. Cochran, R. Boswell, J. Presley, P. Kumar, A. Sathe, Proc. Int’l Conference on Gas Hydrates, 2008. 15. S. Hancock, G. Moridis, S. Wilson, A. Robertson, Proc. Offshore Technology Conference, 2010, OTC21015. 16. Y. Masuda, K. Yamamoto, S. Tadaaki, T. Ebinuma, S. Nagakubo, NETL Fire in the Ice, Fall 2009, 1-6.



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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

Meeting the challenge of deepwater development

O

ver the past decade, the industry has had great success pushing into the deepwater frontier through innovation. However, this success has come with a price. There have been numerous recent high-profile failures, which are estimated to have cost hundreds of millions of dollars of additional capex and lost revenue. While we continue to learn from these incidents, the technology boundary continues to be pushed and, in an environment where time truly is money, the potential for further failure is a major concern. The effect of exploiting reserves in deepwater has been to change the risk and investment profile in which the upstream oil and gas industry has traditionally operated. Wells and facility costs are rising dramatically and the risk of underperformance is increasing. The industry has to deploy more sophisticated technologies, in particular in areas such as downhole completions, subsea hardware, and facilities able to operate in deepwater. Increasingly, the commercial success of a new multi-billion dollar deepwater development can depend on the performance of a small number of new pieces of technology. Assuring the integrity of this technology, and the associated uncertainty introduced, constitutes a new challenge for an industry where the primary expertise has traditionally been in the management of geological uncertainty. A word commonly used by oil company executives these days is “risk,” and for them, the success of their organization can depend on its ability to manage the risk effectively.

Framing the challenge The oil and gas industry has developed procedures to qualify new technology. Whether these are specific company processes or industry practices (e.g. DNV-RP-A203), the assumption is that robust application of these processes will ensure the successful deployment of the technology. However, the deepwater industry has examples where technology deployments have not met expectations. These have resulted in major schedule overruns, escalating capital costs and operational failures. In many cases, a key factor appears to have been an inability to identify and characterize how the new technology would behave in operation. For example, while understanding of

Alistair Warwick

Atkins

ly in field life, caused by a failure mechanism not understood or anticipated by the design, manufacturing, qualification, or testing processes employed. The phrase “you don’t know what you don’t know” is the simplest way to define the problem statement associated with deployment of new technology.

Success factors In 2005 Hurricane Rita capsized the Typhoon facility in the Gulf of Mexico.

lateral pipeline buckling has greatly improved through research and development undertaken by individual projects and Joint Industry Projects [such as the Atkins-led SAFEBUCK], there have been situations where subsea pipeline integrity has been compromised by unanticipated behavior. There have been numerous integrity-related issues associated with technology applied to mitigate flow assurance issues in deepwater, typically associated with hydrate formation. Thick-walled insulated flowlines/risers or pipe-in-pipe systems have been successful in mitigating hydrate formation, but there have also been failures associated with this technology including: • Damage to insulation during the pipelay process • Corrosion under insulation • Lower than predicted fatigue lives of risers, associated with ineffective prediction of the behavior of insulated risers. The behavior of deepwater moored facilities when exposed to hurricanes in the Gulf of Mexico has been another major focus area for the industry in the last decade. Hull design and mooring technology have been stretched to address increasing topsides payload and water depths. While the industry has invested significantly in this area, there have been failures that have resulted in significant damage and in extreme cases total loss of these facilities when exposed to hurricanes. In the majority of these cases, the root cause can be tracked back to a failure of an element of technology to behave as predicted during the design phase. The primary concern with proven technology is that towards the end of its operational life the likelihood of a failure increases significantly. The concern with new technology is that an unexpected failure occurs ear-

However, while there have been many reported failures associated with the deployment of new technology, there have also been significant successes. The industry can learn as much from its successes as it can from its failures, and a review of several examples of successful deployment of new technology reveals a set of consistent and distinguishable factors. This may seem obvious, however it is necessary to clearly define what constitutes new technology. As an industry we have been successful at pushing existing technology, sometimes referred to as stretching technology. When we “stretch” technology, we typically deliver more from a proven piece of technology by implementing a qualification process to increase the rating. However, this introduces the risk that we have not fully understood the impact of the change with respect to the physical characteristics and limitations of the materials of construction. An example would be the use of elastomers for higher temperatures in subsea equipment, where qualification tests may be passed but operational reliability may have been compromised because the physics of how the seal operates may have subtly changed. We must challenge ourselves to define what constitutes new technology to avoid the risk of mistakenly thinking we are taking a small step when in effect we are moving the operational envelope to a place where component characteristics will behave differently than we have historically predicted or seen before.

Engineering principles Regulations, design codes and practices are the industry’s foundation. As engineers, we rely heavily on these to deliver robust fit for purpose designs, equipment and operations. In addition to relying on these foundations, when developing and deploying new technol-



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It’s times like these you need people like us. TM

It’s a tough business. Look to API. ®

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The processes employed to deliver a major deepwater development from the concept selection to the operations phase are established and well understood by the industry. These same processes cannot be used effectively, however, to deliver new technology. While it is essential that the development and deployment of the new technology is interlinked with the overall project delivery, it should be treated as a project in its own right. The definition of success, the processes and procedures employed, and even the engineering teams and supply chains, may all have to be different.

Success rate of new versus proven technologies (source: Atkins).

New technology

Number failures

ogy it is fundamental that we have a full and deep understanding of the engineering principles that apply to the new technology. The majority of regulations, codes, and standards are experience based – they typically lag the development of new technology in the industry, thus sole reliance on these is not sufficient. We must ensure that we develop a deep understanding of the engineering principles behind the technology development; only with this understanding will come the ability to identify the potential failures modes allowing them to be addressed and mitigated. Establish technology readiness levels – are we being honest with ourselves? The space industry introduced the concept of technology readiness levels (TRL) a number of decades ago. Many parts of the oil and gas industry have embodied the concept and implemented TRL processes and management systems. A challenge we face in the oil and gas industry is the expectation to drive maximum value from discovered reserves: a key factor in maximizing this value is shortening the

Proven technology

Time

time to recover the reserves. This places significant pressure to deliver to aggressive schedules. Employing an effective TRL program in a schedule-driven environment can be challenging. Ultimately, the success of that program depends on a robust assessment of the readiness of the technology to move to the next step. The successful deployment of new technology means the ability to stop and realistically evaluate the level of readiness at each stage of the delivery process. In some circumstances this will impact the overall schedule of a project which is a cost the industry must be willing to bear.

Role of suppliers The oil and gas industry has one of the most efficient supply chains of any industry. This efficiency has been driven by the exploration and production companies over many years of effort to drive the maximum value at each stage of the chain. In addition to being efficient, the supply chain has to be effective at delivering the new technology in the coming decades. This will require further development of key aspects of the supply chain including:

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System test, launch, & operations System/subsystem development

TRL 9 TRL 8 TRL 7

Technology demonstration Technology development

TRL 6 TRL 5 TRL 4

Research to prove feasibility Basic technology research

TRL 3 TRL 2 TRL 1

• Collaborative relationships between parties throughout the supply chain • Modifications to work processes that will foster the robust management of new

Why just tell them you’re an expert when you can show them?

The offshore sector is adopting Technology Readiness Levels procedures first devised by the space industry.

technology deployment interfaces along the supply chain • Contracting strategies that will encourage the development of new technology. Developing and deploying new technology introduces risks to the successful delivery of a project. While these risks can be mitigated, it is unlikely that they can be eliminated. As mentioned previously, the success of a multibillion dollar deepwater development can depend on the performance of a small number of new, and largely unproven, pieces of technology, failure of any one of which could jeopardize the success of the overall project. An alternative plan for each element of new technology must therefore be developed to ensure there is an alternate development plan should it not be possible to deploy an individual element of technology. This will offer two main benefits: • The discipline of generating a contingency plan will actually drive a deeper understanding of the key issues that could prevent successful deployment of a piece of new technology

• The ability to implement a contingency plan will ensure more robust decision making when an element of new technology stalls, i.e. having alternatives allow for better evaluation of the optimum way forward.

Innovating with integrity The oil and gas industry must continue to innovate to provide the world with sustainable and affordable energy supplies in an environmentally sound manner. Innovation means the deployment of enabling technology to access the significant oil and gas reserves that still exist globally. History has demonstrated that deploying new technology in a dynamic and challenging environment, like the deepwater oil and gas industry, is not without risk. The industry must employ robust processes and practices, and instill a culture that will facilitate the successful deployment of new enabling technology. For every step we move closer to deploying new technology we must be ready to step backwards to ensure its integrity in operation. Our industry must rise to the challenge and demonstrate to the watching world that we can deliver an essential component of the energy needs of the future in a safe and environmentally sound manner. 

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P R O D U C T I O N O P E R AT I O N S

P&A innovations increase efficiency, safety In the field, a combination of advanced technology and aggressive engineering often provide the best solution

P

lug and abandonment operations face a long list of challenges, including rising costs, safety concerns, environmental issues, and rapidly growing demand. Conventional methods and tools are frequently unable to address these concerns. Instead, the solutions are being found in new technologies that are yielding improved levels of efficiency and performance. These advances contrast with traditional approaches, such as jackup rig installations, that are typically slow-to-mobilize and expensive. Traditional rigless P&A equipment comes with cost and safety concerns, and snubbing units generally expose personnel to safety risks and can be difficult to move from well to well. Many of the recent advances center around the development of versatile and compact rigless intervention and well abandonment systems. These systems are fit for purpose and can include hydraulic pulling and jacking units, cantilever systems with light duty work decks, and casing jack configurations. Lightweight and modular and with a minimal footprint, these systems provide new levels of

Delaney Olstad Philip O’Connor

Weatherford International Ltd.

mobilization and flexibility. They are at the core of a suite of technologies that provide a scalable P&A solution ranging from casing jacks to light-duty work deck and cantilever systems, to full-function pulling and jacking units. Further integration with a larger scope of service draws on multiple resources including wellhead diagnostics, running bridge plugs, tubing cutting and removal, and remedial cementing to improve safety and efficiency. These technologies and capabilities combined provide the tools for innovative, engineered solutions that improve performance on a range of P&A applications.

Growing demand Complicating the P&A picture is the greatly increased demand projected for services due to 2010 changes in decommissioning guidance for wells and platforms in the

Gulf of Mexico. The new guidelines from the Bureau of Ocean Energy, Management, Regulation, and Enforcement are expected to add to activity by making P&A actions dependent on well and structure status instead of the lease status. This anticipated increase comes on the heels of record increases in temporary and permanent abandonments in 2008 and 2009, due in part to hurricane damage. According to a recent webinar conducted by Offshore,1 2009 capital expenditures were $650 million to $1.4 billion, accounting for 835 permanent abandonments, 744 temporary abandonments, and 214 structure removals. The activity is about 50% ahead of a busy 2008. The new decommissioning guidance affects an inventory of approximately 3,500 shallow and deepwater wells that have been idle for five or more years. Those wells must be plugged and abandoned in the next three years. In addition, there are approximately 2,000 wells idle for less than five years and an additional 3,500 wells that have been temporarily abandoned. All told, there is a very large waiting list of P&A operations that must be addressed over a relatively short time period.

New approach Addressing this well inventory will require a marked change in the efficiency and innovation of P&A operations. A key part of this change is the combination of advanced technology and aggressive engineering that is already providing solutions for many P&A challenges. The three following cases, one onshore and two in the Gulf of Mexico (GoM), illustrate the increasing importance of innovative thinking and equipment to P&A performance. This enhanced performance is central to improving safety and reducing costs. Each case depended on continuous communications and extensive collaboration with the clients. All three presented unique circumstances that required innovation and the development of fit-for-purpose components and equipment.

Leaning six-pile platform The pulling and jacking unit is shown, deployed and positioned on the wedge deck.

A 15° lean made P&A work on a hurricanedamaged, six-pile platform particularly challenging. The structure was loaded with pro-



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duction equipment and prior to the storm had been operational with 10 producing wells and one partially drilled conductor. Underwater inspections showed one corner leg of the platform had penetrated the supporting shale on the seafloor and cause the structure to lean. Nevertheless, the structure was found to be relatively stable and well conductor damage was limited to bending at or below the mud line. To conduct P&A operations on the live wells, the platform was secured with a second, four-pile platform positioned at the leaning corner of the structure. Extensive laser surveying established the exact relations of the wellheads to the new structure. Several P&A options were considered and rejected for safety and cost reasons. A snubbing unit would have required a major engineering effort and would have put the wellheads in harm’s way. A jackup rig of sufficient size to cantilever over the well bay area would have been cost prohibitive. A new, lower load rating was established for the compromised structure. These specifications guided the development of a lightweight pulling and jacking unit. A modular design for the unit was used to provide high mobility and a small footprint. An integrated self-clamp skidding system allowed the unit to be easily skidded from well to well. Design of the unit depended on close teamwork with customer personnel and strict attention to platform constraints. Limited deck space required measurement of each equipment component. Exact equipment weights were determined to ensure that the total equipment load on the structure fell within the weight parameters after allowing for an over-pull of approximately 100,000 lb.

Special wedge deck To accommodate the intervention and well abandonment system, which includes the pulling and jacking unit, a specially-designed wedge deck was built and attached to the original drill beams on the damaged structure. Placed over the wells, it provided a level work area for the unit to perform pulling and jacking operations. Plugging and abandoning operations involved an experienced crew working around the clock. Extensive training was conducted to familiarize the crew with the specialized equipment and the risks associated with working on a structure that was leaning at a 15° angle. In phase one of operations, a daylight crew was deployed to the platform to begin the wellhead diagnostics. Phase two involved wireline work and plugging of all open perforations. During this time, the new hydraulic pulling and jacking unit was being manufactured

Jacking units provided the lift to return the wellhead and snubbing unit to vertical.

and set up per the operational requirements and client requests. Tests were performed to simulate bends in the production tubing and casing while running bottomhole assemblies. The intervention and well abandonment system was then deployed to the platform and the pulling and jacking unit was assembled on the new wedge deck. Once the pulling and jacking unit was in place, phase three began. Wireline inspection indicated that several wells would require coiled-tubing work to plug open perforations and meet regulatory requirements. Crane support was limited by winds in excess of 35 mph, so the rigless pulling and jacking unit, which can operate at nearly twice those wind speeds, was used. Significant savings were realized by having the unit support the coiled-tubing operations. The change also freed the crane for other work.

Custom hydraulic clamps Moving the unit from well to well on the structure was efficient with moving times that average an hour on most wells. The skidding process benefited from custom-manufactured, hydraulically actuated clamps that fit on virtually any combination of beam width and flange thickness. On completion of the coiled tubing work, phase four began by perforating, cutting and pulling the production tubing and casing. Safe and efficient retrieval and laying down of tubulars was enhanced by the load

capabilities and compact design of the pulling and jacking unit. An integrated jacking floor was used to remove stuck casing hangers. When a hanger became stuck in the wellhead, it was a simple operation to spear into the tubular to be pulled, and then use the built-in jacking system to remove the stuck hangers. Phase five involved cutting the remaining well casings approximately 15 ft below the mud line. The pipe pulling and jacking features were used to trip 3 1/2-in. OD drill pipe with cutting assemblies into the wells. The cuttings for all of the well conductors were completed without incident. Boring and sawing equipment were used to lay down the cemented well conductors in 40-ft lengths. The pulling and jacking unit was a costeffective, safe, and efficient means to complete the job. It eliminated drilling-rig costs and the development of an alternative method. The unit was manufactured quickly and all necessary work was completed two months ahead of schedule, which resulted in significant cost savings. During the 299 days/49,476 man-hours spent on location, there were 2,276 Job Safety and Environmental Impact Analyses conducted with no recordable injuries or operational and environmental incidents.

Frac damage Failure of a wing valve during fracturing operations on a newly completed 16,000-ft well released pressure that bent the 10 3/4-



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A unique adjustable cantilever system on the lift boat allowed the angle of the wells to be matched.

in. casing at approximately 12° just below the wellhead. After removing the drive pipe and cement to expose the bent casing, it was decided to rig-down the wellheads and remove the damaged pipe. Mobilizing a rig and crew presented significant time and cost constraints. To expedite work and safely cut expenses, the alternative solution specified a 385-ton casing jack, heavy-duty work beams and other specialized P&A equipment. Operations began with removing 5 1/2-in. and 7 5/8-in. casing hangers. Free travel of the hangers required jacking them out at the same angle as the bent casing. The task was complicated by jacking loads of 250,000 lb on the 5 1/2-in. casing and 450,000 lb on the 7 5/8-in. casing. To address the lean, angled beams were set under the jacks to match the bend in the casing. Once the casing-hanger slips were removed, both sets of casing were lowered into the wellbore below the 10 3/4-in. hanger. The damaged 10 3/4-in. casing was then cut off and a new wellhead was installed. The angled beams were replaced with level beams and the original wellhead configuration was restored. The entire operation, including setup and rig-down, was accomplished in two 12-hour days. Fishing operations on the same well resulted in another problem remedied with the P&A equipment. When jarring efforts exceeded compressive limits on the 10 3/4in. casing, the casing collapsed on itself and threatened the stability of a snubbing unit rigged up 97 ft above the surface with 15,000 lb of 2 7/8-in. tubing. To deal with the situation, two 285-ton jacks were mobilized along with two 20-ft high-strength, 12-in. beams. It was determined that a 7 1/6-in., 15,000 psi frac valve on the wellhead was a safe and satisfactory lifting point. The jacks were placed on each side of the wellhead and the beams were placed under the valve. The jacks were simultaneously activated to support the snubbing unit while bringing the system back to a true vertical position. Once the snubbing unit was corrected back to vertical, the tubing was removed and the unit was rigged down. The angled beams were positioned to allow free travel of the casing hanger slips and repositioning of the casing. After the damaged casing was cut off, the level beams were rigged up and a new wellhead was installed.

A hurricane-damaged satellite platform had two wells leaning at approximately 20°. The precarious situation required an innovative P&A solution. Operations had to be conducted at the same angle as the wells because of the concern that an attempt to straighten the wells could result in failure of the casing below the mud line at the bend point. The solution began with the use of a lift boat to support the P&A operations rather than a jackup rig, due to debris on the ocean floor. To address the angled work deck, the lift boat was outfitted with a unique cantilever system and light duty work deck that extended off the side of the boat. Instead of conventionally welding the beams and work deck in place, the cantilever system was built so it could be adjusted to match the angle of the wells. In just two weeks, a clamping system was designed to fasten the cantilever beams to the lift boat and the system was outfitted with two 50,000-lb, single-line winches. The design provided the flexibility needed to position the lift boat and complete the work. On the first well, the P&A procedures involved mechanically cutting and pulling 10 3/4-in. casing and 16-in. casing, which was cemented into 30-in. conductor pipe. The 10 3/4-in. casing was cut using newly-developed guillotine saws. The remotely-operated, multi-string saws are self-aligning and self-clamping to minimize risk to personnel, and feature a hydraulic stabilizer to improve cutting efficiency. When attempting to cut the 16-in. casing, it was discovered and verified by camera that the casing had parted approximately 12 ft above the mud line. The remotely-operated guillotine saw was deployed to a point

approximately 20 ft above the water line to cut off the casings and facilitate entry into the wellbore. Deployed underwater, the saw first cut the 30-in. and 16-in. casing 5 ft above the mud line. Once the sections of casing were retrieved, the loose piece of 16-in. casing was retrieved with a spear run on 3 1/2-in. drill pipe. A hydraulically-actuated mechanical cutter was then deployed on 3 1/2-in. drill pipe, the 30-in. casing was cut 15 ft below the mud line, and the remaining casing and conductor were retrieved without incident. For the second well, the objective was to remove the crow’s nest and cut and pull 9 5/8-in. casing cemented inside 30-in. conductors. To begin the P&A operations, two abandoned pipelines were removed by divers, per (at that time) MMS rules and regulations. Once again, the guillotine saw was deployed to a point below the crow’s nest to cut off the casings and facilitate entry into the wellbore. A hydraulically actuated mechanical cutter was then deployed on 3 1/2-in. drill pipe and the 30 x 9 5/8-in. casing was cut at 15 ft below the mud line. This section of casing and conductor was retrieved without incident. The successful completion of the project was attributed to the timely design and mobilization of the adjustable cantilever system, the ability to work efficiently on the angled work deck, and the efficiency of the remotely operated, self-aligning, self-clamping guillotine saw.

Enhancing P&A performance In each of these cases, a combination of advanced technology and aggressive engineering was key to providing the best solution. The development of the versatile intervention and well abandonment system, including the compact rig-less hydraulic pulling and jacking units are the basis for this capability. Integrated with a broad service resource that draws on P&A and other related capabilities, the technology has proven itself to be an enabler for the innovative, engineered solutions that are increasingly required to improve P&A performance. These enhancements are reducing costs, improving operational efficiency and strengthening safety across a full spectrum of P&A applications from the most basic to the most challenging.  Reference 1. Gulf of Mexico Decommissioning Outlook, Mark Kaiser, Louisiana State University Center for Energy Studies, Offshore, September 2010.



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Post-hurricane decommissioning poses unique challenges In the Gulf of Mexico, 67 destroyed structures have been decommissioned to date; more than 100 remain to be removed Mark J. Kaiser

Center for Energy Studies, Louisiana State University

T

he offshore oil and gas industry in the Gulf of Mexico is susceptible to natural and man-made disasters. From 20042008, five major hurricanes (Ivan, Katrina, Rita, Gustav, Ike) destroyed 180 structures and 1,070 wells (Table 1). In December 2010, 85% of the destroyed wells had been decommissioned but more than half of the destroyed structures remain. Decommissioning operations on destroyed structures are governed by the same regulations and requirements as normal decommissioning but are subject to unique challenges and are more time consuming and expensive. The cost involved in decommissioning destroyed structures often ranges between 10 to 20 times more than conventional abandonment.

Failure modes Offshore oil and gas structures are designed for the environmental conditions in which they operate, and as far as day-today operations go, are extremely safe and reliable. With the occurrence of a tropical storm or hurricane, however, the risks of damage and destruction increase significantly because structures must sustain wind speeds, wave forces, and potential seabed mudslides that may equal or exceed their design capacity. Structures fail in different modes. Structural collapse (toppling) is the most common failure, but structures also may be damaged to the point of condemnation. In most cases, there is no visible structure remaining above the waterline. In some cases, the deck and topsides may be sheared off, leaving the jacket in place, or the structure may be leaning. A platform left standing may be declared destroyed if it can no longer carry out its purpose and there is no economic way to ensure structural stability.

Hurricane-destroyed platforms. Source: BOEMRE, Tetra Technologies Inc.

Table 1. Hurricane damaged and destroyed infrastructure in the Gulf of Mexico (2004-2008). Hurricane

Year

———Structures——— Damaged Destroyed

Ivan 2004 5 7 Katrina 2005 20 45 Rita 2005 23 69 Gustav/Ike 2008 28 59 Total 76 180 a. Original wellbores on destroyed structures, excluding sidetracks.

—Destroyed Wells— Totala Impactedb 87 345 370 410 1,212

83 307 352 328 1,070

b. Original wellbores on destroyed structures not permanently abandoned or temporarily abandoned at the time of destruction.

Old structures are especially vulnerable because they are usually designed to lower environmental criteria. Older platforms generally have lower strength characteristics (e.g., weaker joints, less robust bracing pat-

terns, etc.) and lower deck heights which make them more susceptible to wave-indeck conditions. A wave crest hitting a platform deck creates loads that likely result in significant platform damage and in some



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Table 2. Hurricane destroyed structures that have been decommissioned and require decommissioning circa December 2010. Hurricane Ivan Katrina Rita Gustav/Ike Total

—Destroyed Producers— Removed Remaining 5 22 20 12 59

1 20 41 36 98

—Destroyed Auxiliary— Removed Remaining 1 3 2 2 8

0 0 6 9 15

Table 3. Hurricane destroyed wells that have been abandoned and require abandonment circa December 2010. Hurricane

Original Wellboresa

Ivan 83 Katrina 307 Rita 352 Gustav/Ike 328 Total 1,070 a. Excludes sidetrack wells.

Abandoned Wells

Wells Remaining to be Abandoned

Percent of Original

62 273 311 279 925

21 34 41 49 145

25 11 12 15 14

Environmental impacts Wells may either bend or be sheared above, at, or below the mudline. Pipes deform and break. One of the first requirements is to stop leaking wells or to collect the hydrocarbon release. Toppled structures cannot undergo the normal topsides inspection and preparation, but these operations still need to be performed. There are potential environmental hazards due to hydrocarbon release from equipment, tanks, pipelines, etc. and hazardous substances such as batteries and asbestos. Operational constraints Dismantling a platform in pieces is one of the most hazardous options due to the extensive diver exposure, duration of operations, and nature of activity. Therefore, it is not frequently performed. Bulk explosives may not be feasible because of the condition of the deformed jacket and because placement may not be possible at the minimum legal depth. Below mud line cutters require diver assistance for excavation and cutting, but uncertain structural issues may preclude this option. Cost The cost involved in decommissioning destroyed structures often range between 10 to 20 times more than conventional abandonment because of these factors.

cases collapse. A key ingredient in surviving hurricanes is to have a deck elevation above the largest hurricane waves.

Stages of decommissioning

Decommissioning challenges

Unconventional decommissioning follows similar steps to normal decommissioning operations.

As noted above, decommissioning operations on destroyed structures are governed by the same regulations and requirements as normal decommissioning but are subject to unique challenges and are more time consuming and expensive than normal operations. Extensive planning Planning and execution for hurricane destroyed structures is more complicated than normal decommissioning, and operations are subject to additional safety issues and hazards. Extensive planning is required to develop proper work plans, cutting and lifting requirements, and to minimize diver exposure. Diver exposure and safety Diving is inherently dangerous under normal conditions with injuries and fatalities commonly associated with burning, jetting, and salvage operations. Conducting these activities in the debris field and among deformed piping/structures expose divers to significantly greater risk if not managed properly. Depending on the location and water depth, there may be limited and at times zero visibility. Spatial information To develop work plans and structural analysis models, spatial information for each toppled structure is required. Data collection and analysis employ remote sensing devices, towed side scan sonar, ROV mounted sector scanning sonar, and pole and ROV mounted multibeam echosounder surveys. Unlike conventional operations, finite element and ultimate strength analysis are required at various stages and prior to lift operations. Debris fields Large debris fields from deck and structural members, and material and equipment on the decks, are associated with toppled structures. Debris needs to be removed to satisfy site clearance requirements and divers often are employed to identify the debris and to assist in its transfer to the surface. The water depth of the structure and the expected work duration determine the need for air or saturation diving.

Site assessment The first step is to assess the site and to develop work plans to access the wells safely and to remove debris. Spatial information and structural models are required to plan cutting and lifting operations, well abandonment, and structure removal. Divers and ROVs are used to gather underwater site assessment data and computer assisted drafting is used to create a 3D image of the structure as a visual reference for understanding the access to well bays, conductors, and equipment. Models of the downed structure incorporate the “as built” drawings with the “as is” configuration, and form the basis of engineering analysis and operational planning. Clearing the structure Debris over and around the wells is identified and cleared depending on the sequence of cutting and lifting operations. Depending on how the structure collapsed, the legs may pull up over the conductors, wells may pull out of the deck, and wells may be tangled in debris. Wellheads may be inside the deck structure and either inaccessible or accessible but inoperable. Debris may need to be cleared before accessing the well or there may be good access to the wells. The debris field, visibility at the seafloor, and hazards associated with underwater burning expose divers to significant risk. P&A Destroyed wells are not in their customary upright (vertical) condition and routine abandonment procedures cannot be implemented. Well access is complicated by the debris field around the toppled structure, the twisted structural members, vessels and piping containing hydrocarbons, and bent pipes and risers. Long arches on conductors indicate they may go deeper than expected, requiring jetting operations to remove soil from around the wellbore. How deep the bends are below the mudline and how much vertical pipe is needed varies with each downed platform. If the well is under pressure, it will be necessary to hot tap. In extreme cases, an operator may have to drill a new well to access the old well.



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conference & exhibition 11-13 october 2011 hilton riverside | new orleans | usa

30 years of covering the

deep issues For 30 years Deep Offshore Technology International has been showcasing pioneering technology that has been shaping the future of the deep and ultra-deepwater industry. Showcasing the most innovative technologies designed to withstand hostile and ultra deepwater environments. Discussing the specific challenges of the region and the latest groundbreaking solutions. DOT puts you at the heart of the leading industry forum which attracts the key industry experts and decision makers from the major E&P companies. Don’t miss your chance to join the distinguished list of exhibitors, delegates and visitors. For more information on exhibiting and sponsorship please contact:

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Pipeline abandonment Severe weather can move pipelines outside their original bed, break them from risers and junctions, and twist adjacent lines together. The contents of the lines may contain hydrocarbons if they did not drain when the pipe broke. Lines are hot-tapped, flushed, and then cut and removed. Containment domes may be deployed to capture hydrocarbons that might escape during operation. Due to potential stored energy in damaged or deformed pipelines, care must be taken during cutting operations on bent members. Various “strongback” tools were developed by industry to control pipe movement when severed. Structure removal Topside facilities, deck, and jacket removal is the core of every decommissioning project and frequently the most expensive stage in normal operations. In conventional decommissioning, sections are removed in the reverse order in which they were installed − deck and topsides equipment, jacket and pile removal. For a destroyed structure, the work paths may overlap and the sequence of cut and lift operations will be specific to the configuration of the structure damage. Following are descriptions of key removal operations. Conductor removal. Conductors need to be cut and lifted from the seabed. Normally, conductor removal involves three procedures: cutting, pulling/sectioning, and offloading. Cutting requires the use of explosives, mechanical cutters, or abrasive water jets to make the cuts at least 15 ft (5 m) below the mudline. Divers perform the operations or set up the cutting tools. A derrick barge lifts conductors from the seabed. This lifting involves more preparation than similar work in normal operations. Deck removal. Removing toppled decks pose unique challenges because of their size and weight, location, placement, attachment constraints, and the lack of suitable lift vessels to perform the operation. Dual barge-mounted truss systems were used extensively to remove the decks of toppled structures. Preparing for the deck lift is a complex process. An underwater survey and finite element analysis is used to develop a rigging plan and to estimate the lift weight and loading as the structure is pulled through the water column. Lift assemblies are designed and fabricated, and divers clear loose debris, remove the crane boom and prepare the production equipment by flushing and blinding the open-ended pipes. Access points in the deck need to be cut before installing lifting hooks. Jacket removal. After the conductors and

Table 4. Hurricane damaged and destroyed infrastructure categorized by operator. Operator Anglo-Suisse Offshore Apache APEX Oil and Gas Arena Offshore ATP Oil & Gas Corporation B T Operating Berly Oil and Gas Bois D’Arc Offshore BP Callon Petroleum Century Exploration Chevron Conn Energy ConocoPhillips Company Devon Energy Dominion East Cameron Partners EL PASO Energy Partners Energy Resource Technology Energy XXI GOM Exxon Mobil Forest Oil Gulf of Mexico Oil & Gas Properties Linder Oil Company Mariner Energy Maritech Resources Marlin Energy McMoRan Merit Energy Murphy NCX Company Newfield Exploration Nexen Petroleum Noble Energy PetroQuest Energy Pioneer Natural Resources Samson Samson Contour Energy E&P Shell SPN Resources St. Mary Land Exploration St. Mary Energy Company Sterling Energy Stone Energy Taylor Energy Texaco E&P The Houston Exploration TOTAL UNOCAL W & T Offshore Walter Oil & Gas Williams Field Services Total

——Structuresa—— Damaged Destroyed 1 6 – 3 1 – 1 – 1 1 – 4 – 1 – 1 – 4 – 2 – 3 10 – – 5 1 2 1 2 1 1 5 1 – – – – – 5 – – – – 2 2 – – 2 1 4 1 1 76

4 14 1 – – 1 2 1 14 – 1 22 1 – 4 1 1 1 3 6 2 – 7 1 1 3 5 9 3 2 – 1 5 2 4 1 1 1 1 1 2 1 1 1 11 1 2 1 – 6 3 1 – 157

——Destroyed Wells—— Totalb Impactedc 55 110 1 – – 4 12 3 99 – 8 224 8 – 70 4 1 5 10 31 4 – 25 2 1 31 41 13 20 22 – 25 22 3 78 1 24 3 6 23 12 5 6 1 57 31 21 2 – 51 34 3 – 1,212

43 103 1 – – 4 12 3 89 – 8 202 5 – 63 4 1 5 10 30 4 – 24 2 1 29 29 13 16 10 – 19 22 3 78 1 23 3 4 – 7 5 6 1 50 27 21 2 – 51 34 2 – 1,070

a. All structures destroyed or damaged, excluding auxiliary (non-producing) structures. b. Original wellbores on destroyed structures, excluding sidetracks. c. Original wellbores on destroyed structures not permanently abandoned or temporarily abandoned at the time of destruction.



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6th Annual Conference & Exhibition 29 - 31 March 2011 Sands Expo & Convention Center Marina Bay Sands, Singapore www.offshoreasiaevent.com

EMERGING TRENDS. CURRENT SOLUTIONS. REGISTER BEFORE 12 February 2011 and save over 20% * In the current climate a reliable, industry leading source of information is needed to show the direction and future opportunities for the industry – Offshore Asia Conference & Exhibition 2011 is that leader. An exclusive source of information for the industry for over 5 years, the event provides a unique platform for success. Whether you seek the latest product enhancing solutions or an exclusive insight into future market trends Offshore Asia has it covered. Be part of THE event that brings together the people, products, and information that drives the industry forward. Offshore Asia recently announced the new LNG track. Presentations in the LNG track will examine the unique nature of Asia-Pacific LNG trade. Boasting the world’s leading LNG importers in Japan and South Korea, the region also has grown into a major supply source, based especially in Indonesia and Australia. For more information please visit:

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piles are cut and removed, the jacket structure is lifted out of the water and placed on a cargo barge. If the integrity of the platform is sufficient, the platform can be lifted and transported to shore or to a reef site. Otherwise, the damaged or toppled structure will be cut and removed in pieces, or dismantled in a manner that satisfies site clearance requirements. In some cases, the jacket may be left in place if the site is designated as a Special Artificial Reef Site (SARS) and U.S. Coast Guard clearance requirements can be satisfied. Because of the large number of SARS applications after the 2004-2008 hurricanes, the program is no longer accepting new applicants until a systematic review is complete. Site clearance and verification The last stage in decommissioning is site clearance and verification. Site clearance is the process of eliminating, or otherwise addressing, potential problems from debris and seafloor disturbances. Verification ensures that the site is clear of obstructions. For hurricane destroyed structures, the amount of debris is likely to be significantly greater than for normal operations. Cutting leads to more steel members across the site, so divers will be required for clearance which adds to the cost of the operation.

Unconventional decommissioning: the numbers and statistics A few key statistics regarding decommissioning in the Gulf of Mexico following the 2004-2008 hurricane seasons are provided below. Structure removal The number of structures destroyed in the 2004-2008 hurricane seasons that have been removed circa December 2010 are depicted in Table 2. In total, 67 destroyed structures have been decommissioned and 113 destroyed structures remain to be removed. Most of the remaining structures are previously producing fixed platforms residing within 300 ft water depth. These structures are held by a large number of operators; in total, 36 operators hold be-

tween one and 18 structures. Delays in removal are due likely to the complexity of the operations or redevelopment considerations. All wells at destroyed structures need to be abandoned before the structure can be decommissioned, and delays on well abandonments delay structure removals. Well abandonment The number of wellbores associated with the inventory of destroyed structures is shown in Table 3. A total of 1,070 wellbores were destroyed in the storms and a total of 925 wells were permanently and temporarily abandoned through December 2010. Hence, about 85% of the destroyed well inventory has been abandoned. All the destroyed wells and structures from hurricane Ivan have been decommissioned except Taylor Energy’s eight-pile fixed platform in MC-20 and its 21 remaining wells. Hurricanes Katrina and Rita destroyed 659 wellbores; 584 of these have been abandoned circa December 2010. Hurricanes Gustav and Ike destroyed 328 wells, and 279 of these have been abandoned. Operator activity A summary of the damaged and destroyed structures and wells sorted by operator is in Table 4. Chevron, BP, Apache, and Stone had the most destroyed structures and wells over 2004-2008, about 40% of the total inventory. In December 2010, Chevron has 18 destroyed structures and 34 wells that remain to be decommissioned. Apache and BP have plugged all of their wells and removed about half of their destroyed structures. Anglo-Suisse, Taylor Energy, and Stone Energy each have a dozen or so wells remaining to plug. A list of operator activity circa December 2010 and a more detailed discussion of the challenges and issues of unconventional decommissioning is available from PennWell.  Editor’s note: This article highlights an upcoming report on Unconventional Decommissioning in the Gulf of Mexico available from PennWell Executive Reports.

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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. This 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 this year’s conference. You can’t afford to miss it.


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Gas-lift valve design addresses long-term well integrity needs ‘Barrier’ technology good for life of well Alan Brodie

Petroleum Technology Co.

Gas lift valve check valve module.

O

n most production facilities the number of industrial flammable gas bottles allowed on-site at any one time is kept to a low number. They are always stored away from locations where heavy lifting operations take place, where the risk of dropped objects increases dramatically. Potential sources of radiant heat are also avoided. Consider, then, that the annulus of just one gas-lifted well can easily contain the equivalent of over 1,000 industrial-sized gas bottles. Even where downhole annulus safety valves (DH-ASVs) are deployed to minimize the capacity, the volume can still be the equivalent of more than 200 gas bottles per well. And heavy lifts are commonplace in well bays where annulus flowlines connecting the high-pressure lift gas supply header to each individual well are located. The worst safety incident ever to occur in the North Sea was the Piper Alpha disaster in 1988. Release of lift gas from the well annuli was not the initial cause of the fire. However it did exacerbate the situation following annulus lift gas injection line failures, due to radiant heat from adjacent fires. This resulted in the ignition of high-pressure lift gas venting from well annuli, a situation which was made worse by the failure of the check valve in many of the downhole gas lift valves. Consequently many of the wells flowed naturally via the tubing/production casing annulus and then into the well bay via damaged gas lift injection lines, where the effluent was ignited.

control devices for side-pocket mandrels” states: “These devices are designed and intended to prevent reverse flow through a flow control device. They are not designed nor intended to provide a tight shut-off pressure safety seal or to be a part of the safety system.” The same is generally true of DH ASVs. In most cases they do not provide a 100% barrier to flow or a tight shut off safety seal.

ALARP requirements

The industry worldwide is largely self-regulated regarding well integrity. Operating companies are required to demonstrate that the risks of hydrocarbon release are as low as reasonably practicable (ALARP) by “using the best equipment, and industry best-practice.” To keep risks ALARP in gas lift completion designs, new technologies have been developed and are increasingly being adopted, namely: • Downhole gas lift valves, which could be relied upon to provide a Well integrity concerns “well integrity barrier” throughout the life of the well, thus mainWith all of this in mind, and the recent focus on well integrity taining the integrity of the primary well containment envelope following the Macondo incident, many major • Actuated wellhead safety valves, located operating companies are looking to eliminate within the body of the wellhead, can be the well integrity compromises that have prerelied upon to close in the event of damviously existed in their gas lift well designs, age to the HP lift gas flowline. This aswith particular with regard to: sures the integrity of the secondary well • Gas lift check valves, which were never containment envelope and significantly designed to be leak tight and were also reduces the inventory of gas that could proving unreliable, thus compromising vent in the case of a HP gas lift line failthe integrity of the primary well containure. ment envelope (the tubing string) Conveniently, these technologies can be • The risk of high pressure gas venting readily retrofitted, without the need for exfrom the annulus in the event that the HP pensive workovers. lift gas flowline or wellhead fixture to the In 2010, Statoil published a paper at OTC annulus is damaged. on improving gas lift valve reliability. It deIt’s amazing that the industry has taken scribed its new validation program based on so long to respond to these risks. Various standards used for packers and plugs (ISO API and ISO documents have until now only 14310:2008), which has a leak criterion (for highlighted the issue, without specifically ad- PTC Modular surface annulus safety (M-SAS) gas) of 20cc/10 min. dressing it. For instance ISO 17078-2 “Flow valve with valve and actuator. It also states: “Strong evidence from both 98 Offshore February 2011 • www.offshore-mag.com


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Safelift Check Valve module.

PTC’s Safelift gas-lift valves.

check valve spring location (around the dart) and size allows for it to be more robust than on traditional valves, requiring an opening pressure differential across the valve orifice of 25 psi (1.72 bar). In a traditional gas lift check valve design, the flow stream usually impinges directly on the check valve seal face, which is normally held in place using a relatively lightweight spring which leads to a relatively small valve movement. As a result, erosive velocities across the valve seal faces are high and the valves have a tendency to chatter. Both of these conditions result in premature seal failure. The Safelift check valve design, however, addresses these shortcomings and as a result valve performance, reliability, and longevity is superior. The injection pressure operated (IPO) unloading valves employ a unique, bellows unloading valve module. The bellows are rated to 10,000 psi (689 bar), which facilitates very deep gas lift valve deployment. Despite this high pressure rating, the bellows are much less stiff than traditional bellows, allowing for unusually long valve stem travel. Unlike traditional valves, the function of the bellows is not to provide the force to hold the valve closed on its seat. Instead, a spring is used to hold the valve closed (the bellows serves to retract the valve off seat). In the event of dome pressure loss or bellows failure, the unloading valve is designed to fail-safe in the closed position. In any case, since the valves employ metal/metal seal N2 domes and pressure-balanced edge welded bellows, the likelihood of dome pressure loss in these valves is low. The bellows OD is also larger than that used in traditional gas lift valves; and, as a result, the valves are less sensitive to tubing pressure variations. The unusually long bellows travel also means the valve suffers very little from throttling and the unloader module is essentially invisible to flow when fully open. Consequently, shallow-set Safelift IPO unloading valves are now being deployed for long-term gas lifting (essentially as a back-up operating valve in cases where operating conditions change unexpectedly), without concerns of accelerated time to failure. the lab and the field suggest that the valve developed to the validation program is considerably more robust and has an extended lifetime in harsh conditions. The increased robustness and lifetime will increase the safety level of the well and reduce intervention time and cost.” A number of “well barrier” downhole gas lift valves now available meet the ISO 14310 factory acceptance test (FAT). However, gas lift valves are invariably exposed to erosive fluids at some time. Consequently some operating companies are insisting that FAT testing should be repeated after flowing erosive fluid through the valve. PTC developed Safelift gas lift valves (GLVs) in response to the industry’s demand for such a valve. They have been tested and verified ISO 14310:2008 following the circulation of up to 600 bbl of water at up to 3 bbl/min with up to 4 kg/cu m of barite. We believe this is a unique capability – these valves are designed to provide integrity for the life of a well, not just to pass an FAT. These valves are essentially modular. All valves in the family incorporate the same check valve module. These were designed using computational fluid dynamics to ensure the check valve flow paths and the opening dimensions were optimized with respect to erosion across the metal/metal seal faces. The orifice or gas lift valve choke also moves with the check valve as it opens, which significantly reduces chattering. And finally, the

SAS Valves PTC’s actuated SAS valves offer protection against the release of a large volume of high pressure lift gas from the well annulus if the surface lines are damaged. The check valve design is similar to that employed in our gas-lift valves, providing higher integrity and reliability than traditional gas lift line check valves. The SAS range is designed and tested in accordance to API 6A PSL 3G PR2, and fire tested in accordance to API 6FB and API 6FD, exceeding the testing criteria by achieving V0 (zero bubbles) with gas as test medium. The valves are actuated (held open/fail-safe closed) using the christmas tree ESD system. Consequently they are not prone to wear and tear due to chattering in fluctuating gas delivery conditions. This means that the valve seal faces are protected, remaining in excellent condition, when sealing is required. It is designed to be installed inside a VR profile within the wellhead. The modular design of the M-SAS allows detachment on severe impact, leaving the check valve undamaged and intact in the VR profile. The H-SAS is an integrated actuator version of the valve. It is used in cases where the wellhead flange is long enough to accommodate both the VR check valve and actuator in one assembly.  www.offshore-mag.com • February 2011 Offshore 99


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Demand for emergency management training on the rise Paul Groves

Petrofac Training Services

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voice comes over the radio. The pilot of an inbound helicopter is just two minutes away from the offshore installation and is experiencing vibrations. He has lost control and is preparing to make a hard landing. The installation’s Control Room operator reports news of the confirmed emergency to the offshore installation manager (OIM) and the control room team. As the team musters in the control room, the unmistakeable sound of an approaching helicopter is followed by a thunderous crash and explosion as scraps of metal and debris collide on the helideck. A multiple casualty incident just occurred. The emergency response effort in the minutes that follow will be critical to the outcome and severity of the crisis situation. Now imagine having the opportunity to role play the emergency response efforts. Simulate in a controlled, monitored environment the experience of a helicopter crash, but without the actual disaster. That is exactly what Major Emergency Management (MEM) training is designed to do. The course, offered by Petrofac Training Services, helps emergency managers and teams develop the core competencies required in a crisis – effective leadership, decision making, delegation, communication, team work, and stress management – by enacting simulated emergency response exercises. MEM training has emerged globally to become a core safety training offering for oil and gas personnel with emergency response roles. The course uses a simulation suite fully equipped with IT and audio-visual capabilities to replicate the same sights, sounds, and stresses experienced during an emergency. The training typically lasts four to five days, depending on the training provider and the employer’s requirements. The course can be customized for operators or drilling and service companies, whether onshore or offshore, by incorporating specific facility models such as mobile offshore drilling units and fixed or floating production facilities, onshore terminals, and refineries.

Participants during role-play scenarios.

The classroom, theory-based portion of the course covers topics such as emergency preparedness and stress management; while the practical, hands-on portion enacts simulated emergency scenarios in which participants take turns in the various emergency team roles – including the emergency manager, often called the OIM, Person In Charge, or on-scene commander. Scenarios vary in complexity and can range from loss of communication, to asset damage, to missing personnel. Some scenarios are designed to be controllable if properly managed; others are intended to require facility evacuation. To make scenarios as realistic as possible, the exercises take place in a simulated, staged control room or command center to create interactive process and operating systems. The scenarios incorporate the use of Emergency Response Plans (ERPs), work permits, radios, alarms, and information boards to further heighten realism. Courses can use generic props or be tailored to an employer’s requirements, often using the same facility designs, station bills, POB lists, and ERPs. After each scenario, a de-briefing is held to review what went well and what could be improved for the individual and the team. A key to the course is that it continually

measures the ability of the participant to perform emergency management duties to a specified standard by incorporation of an appraisal process. The appraisal process also is customized to the employer’s needs, ranging from informal assessments to fullscale appraisals in which trained assessors evaluate participants.

Evolution of MEM Many lessons stem from the Piper Alpha disaster in 1988 which claimed the lives of 167 of the 229 crew members on board the North Sea installation and brought about sweeping changes to offshore safety regulations in the UK. One such lesson was the unmistakable need for increased crisis situation training for offshore managers. Following the Piper Alpha disaster, a new safety case regime was introduced in the UK. In 1992, regulations were introduced which require every Duty Holder of an installation on the UK continental shelf to document and submit how its safety management system would mitigate the risks associated with its operations. One requirement of the safety case is the need for the Duty Holder to demonstrate that its offshore managers are competent to lead in an emergency situation. This requirement further specifies that managers should be assessed



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in their ability to command in an emergency. MEM training was developed later to help the industry meet these new requirements. The UK Offshore Operators Association worked to establish guidelines and a standard-setting industry body then developed a training standard for the course and the appraisal process. Since the Deepwater Horizon incident on April 20, 2010, which resulted in the loss of 11 lives, US regulators have worked to bring about effective safety reforms. The Department of the Interior is reviewing the safety case approach, which, since implementation in the UK, has been put in place by a number of oil-producing countries around the globe. It is still too early to tell whether the US will adopt a safety case approach and what the possible requirements might entail. Regardless of the regulatory changes to come in the US, companies will need to develop comprehensive plans to mitigate risks and hazards. The need for safety training such as MEM is likely to be considered. Many companies operating in the US already have an internal training requirement for their emergency mangers to complete the course which is seen as an internal best practice.

Market trends Petrofac Training Services has delivered MEM training for nearly 20 years and has seen demand for the course double across its global operations in 2010. In the US, a second MEM simulation suite was opened at the company’s Houston Training Center to better support the increased demand. A number of international operating and drilling companies have set internal standards for the training. For example, one oil operator has plans to move to a standardized course delivery by requiring designated emergency managers, regardless of geographic location, to complete MEM training that is approved by a standard-setting industry body. In addition, a number of companies are sending members of extended onshore support teams to the training as well as their emergency managers. In the US, Petrofac Training Services recently created a condensed version of the training to give exposure to those response personnel who will never manage an emergency but will play a role in response efforts.

Our Tradition Runs 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

Benefits of MEM The effectiveness of the course is due largely to the fact that all the core competencies of an emergency manager are tested. Participants must practice their ability to assess the situation, take action while under pressure, and implement emergency response plans while effectively maintaining communication and delegating authority. Course participants often cite increased confidence in their ability to make decisions under pressure after successful completion of the training. On the other hand, participants who are found “not yet competent” after an appraisal are given the support, training, and development opportunities needed to close any competence gaps. Another common response from participants is their realization that effective team work is critical. One person cannot manage all the moving parts in an emergency. A team must be relied upon to share information and carry out actions. While each role plays a distinct and critical part, the team’s interaction drastically impacts how effective it will be at emergency escalation prevention. Because there will always be risks and hazards in the oil and gas industry, regulators and the industry must continue to learn from lessons of the past and work together to ensure the highest levels of safety and emergency response. It is a positive sign that the demand for MEM training continues to increase, as this important safety training helps the world’s emergency managers develop the competencies needed to effectively manage emergency situations. 

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SUBSEA

Meeting the challenges of subsea boosting To optimize safety, the booster pump system needs to be integrated into both the startup and shutdown process

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he addition of subsea booster pumping to a development increases the complexity of the safety system integration task over that of conventional subsea field developments. More conventional developments typically only deal with a subsea production control system and a topsides process control system. In any subsea project, a control systems integration team should be formed as early as possible to flush out potential danger areas, and to establish the safety and shutdown philosophies to follow throughout the project. It is easy to procrastinate when it comes to controls tasks. Just remember the old saying: “You can pay now, or you can pay later.” This is always true when it comes to safety. In the early life of a subsea development that uses seabed booster pumps, when the shut-in pressure is still high, the possibility of over-pressurizing the pipeline downstream of the subsea pump(s) looms. This danger, combined with the need to weave the pump control hardware as safely and reliably as possible into an existing platform safety system, brings a new dimension to the project conference tables where decisions are made about control systems integration to ensure the safety of personnel and the environment. The booster pump system must not over pressurize the pipeline, and must respond appropriately to all emergency and process safety conditions. Over pressuring the pipeline can be prevented with the use of local interlocks (interlocks with conditions and outputs from the booster pump control system only), and global interlocks (interlocks with conditions and outputs from multiple control systems). A simple example of a local interlock is to prevent booster pump from running while the pump discharge valve and pump re-circulation valve (if included) are closed. In that case, both conditions, and the output – pump disable – are local to the booster

Mike McKinley

Technip

pump control system. A simple global interlock would prevent the booster pump from running while the platform boarding valve on that flowline is closed. In this case, the condition indication – boarding valve position – comes from the platform system, and the action output – pump disable – is executed by the booster pump control system. The platform’s traditional safety system, boarding valves, and flowline PSHL sensors must be the primary overall safety devices. Interlocks built into the systems reflect good operating practices and aid in prevention of a shutdown. Nevertheless, the task of defining interlock method, structure, and data flow is amplified with the introduction of additional subsea equipment, especially one that plays a role in the field’s safety system. A comprehensive interlock philosophy should be agreed upon and developed together by the different subsea controls groups, the topsides control group, and the operations group. To respond appropriately to all emergency and process safety conditions, the booster pump system must be incorporated into the overall system’s cause and effect logic. Columns need to be added to show how the booster pump system responds to vari-

ous platform- and subsea-generated shutdowns. If the system is designed such that shutdown conditions can originate from the booster pump system, then the cause and effect charts are the place to document that. A comprehensive shutdown philosophy also must be agreed upon and developed together by the different subsea controls groups and the topsides control group. Systems at different layers have different shutdown responsibilities. Usually, the platform control system is responsible for protection of personnel and environment. Two examples are: • The platform system controls the subsea production control system HPU vent valves during an ESD. This becomes invaluable if communications are lost between the subsea production control system and the subsea production control pods. When the subsea production control system cannot close relevant safety valves, the platform will be able to. • The platform system controls the main booster pump circuit breakers. If the booster pump control system cannot shut down a pump, and that risks pipeline over-pressurization, the platform system “pulls the plug.” Likewise, the sub-systems, subsea production control system, and subsea booster pump control system, are responsible for protection of assets. Two examples of this are: • The subsea production control system controls tree valve closures during a non-emergency operation.

Evolution of subsea control systems integration with a platform. Without subsea boosting is on the left and with subsea boosting is on the right.



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SUBSEA

Typical topsides network and subsea instrumentation for development with subsea pumping.

Control room Platform servers

• The subsea booster pump control system functions valves on the pump station during a shutdown to isolate the pump from the product stream and to prevent backflow which could harm the pump. A subsea production development in the Gulf of Mexico must comply with Minerals Management Service (now Bureau of Ocean Energy Management, Regulation, and Enforcement) Document NTL No. 2009-G36 Using Alternate Compliance in Safety Systems for Subsea Production Operations, Effective Jan. 1, 2010. Appendix A – Valve Closure Timing, Electro-Hydraulic Control System – provides federal maximum allowable closure times for the five different shutdown conditions as defined by MMS: Process Upset, Pipeline PSHL, ESD/ TSE (Platform), Subsea ESD (Platform), and Subsea ESD (MODU). For each condition, the maximum allowable closure times are defined for boarding valves, underwater safety valve(s) (USV1, 2), surfacecontrolled subsea safety valves (SCSSV), and production hydraulic supply venting. For example, upon sensor activation of a platform emergency shutdown or temperature safety element device, boarding valves must close within 45 seconds, USV1 must close within 20 minutes (five-minute re-settable timer), USV2, if used, must close within 20 minutes, SCSSVs must close within 60 minutes (20-minute resettable timer), and production hydraulics must vent within 24 hours (60-minute re-settable timers). It is important to note that of the above listed five shutdowns defined by the MMS, a booster pump control system classifies them all as either: • Emergency shutdown (ESD): Shutdown all pumps in a field • Flowline shutdown (FSD): Shutdown all pumps feeding an affected flowline. As of press time, the MMS had not yet released safety regulations pertaining to subsea booster pump systems. However, their development is in progress, and specific requirements for subsea sensors and pump shut

Process safety system Emergency safety system Vent

Variable frequency drive Pump control cabinet

Production control cabinet

Production HPU

Boarding valve

Pump station

Tree

SCSSV MPFM

in timings are expected. Until new subsea booster pump regulations are released, so the operator must weave booster pump shutdown timings into those defined in Document NTL No. 2009-G36-Appendix A for alternate field cases, and submit it to BOEMRE for approval. This is done by answering the question: When is it dangerous to personnel or the environment to leave a booster pump running? You do not want to keep pumping oil to a platform that has detected an emergency condition such as a fire or high pressure, and you do not want to keep pumping oil towards a closed boarding valve, risking pipeline over-pressurization. So, just as a platform’s first response to minimize danger is to close all boarding valves, the booster pump system also must shut down pumps to prevent pipeline over-pressurization. The mechanics of how to do this reliably has to be agreed on philosophically by topsides and the pump team, and accepted by BOEMRE. ESDs typically transmit via hardwired contact closures to the subsea production control system. There is no reason to deviate from that for a booster pump control

Data link Subsea Production Control System ......................................... Process Control System Subsea Production Control System .......................................... Subsea Control Module Subsea Booster Pump Control System ................................... Variable Frequency Drive Subsea Booster Pump Control System .................................... Process Control System Subsea Booster Pump Control System .......................... Booster Pump Control Module MultiPhase Flow Meter System ................................................ Process Control System

Examples of communication channels that can fail.

system. Details such as whether or not the booster pump control system can issue the first shutdown request to the variable frequency drive (VFD), then, if unsuccessful, the platform thrown the main breaker, are issues to be worked out as early as possible. The booster pump system not only needs to weave seamlessly into the shutdown process, but also plays a part in starting back up, the “reset” process. Reset logic is what prevents an operator from abandoning a shutdown before a safe state is reached. Typically, a reset button is available to an operator with sufficient security access. He may press it at any time, but it will only be active on a momentary basis. All shutdown operation conditions in the field must be cleared before a reset will execute. If the operator presses reset before all of the previously selected valves are closed, the reset will not execute, and the operator will have to try it again later. One other fault that ties into safety is loss of communications. Each new piece of subsea kit added brings new communication paths that can fail. Each failure must be analyzed for impact on personnel and environment in order to determine the appropriate response. Responses to different communication failures vary. Some result in a shutdown, some will not. Responses to each communication loss must be well thought out and defined by the operator. In some cases an alarm will suffice. Other cases may call for manual shutdown of the subsea production system, or shutdown of one or more booster pumps.  www.offshore-mag.com • February 2011 Offshore 103


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FLOWLINES AND PIPELINES

Radioisotope technology helps ensure pipeline flow Operators use tracers, scanning to measure subsea pipeline contents and to locate blockages Matt Wilson

Tracerco

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he growing demand for fossil fuels means an increasing number of subsea pipelines to transport the oil and gas. This, in turn, has led to the application of various radioisotope technologies to help offshore operators achieve effective pipeline flow assurance. These well-established and radiologically safe techniques are similar to the way in which the medical profession uses X-rays and radioisotopes to diagnose clinical conditions. For example, a pipeline assessment is similar to an X-ray of a patient in that it allows analysis of the object’s contents non-intrusively, whether those contents are hydrocarbons or human bones. In the medical world, a patient can ingest low energy barium so an internal assessment can be made on the condition of his digestive tract. Similar assessments can be made of pipeline and process systems by introducing an appropriate isotope. The technology offers several types of inspection services for pipelines that are in operation. The data determines whether local deposits have caused blockages, and whether they are present in limited locations or distributed through the line. The total volume of deposits and percentage bore restriction within the pipeline also can be identified. Measurements can tell whether the annulus of a pipe-in-pipe system is dry or flooded with seawater or product. In combination with pig tracking, radioisotopes are indispensable for pipe assessment or for leak detection. The technology also has been developed to establish pipeline conditions over time with a non-intrusive wall thinning assessment. These techniques can increase productivity, lower operational costs, and allow the optimization of downtime.

Longer tiebacks As remaining reserves of oil and gas become more difficult to access and fields previously not economical become viable, there is an increasing requirement for longer subsea tiebacks to production facilities. The flowlines in longer tiebacks are more prone to blockage from deposits such as hydrates or waxes. As assets mature and as pipelines require more routine inspection, non-intrusive measurements are an essential tool to reduce downtime. Over the life of an asset, it is important that the challenges of aging are addressed with effective and reliable techniques. If deposits/blockages and corrosion points form, they can be examined and quantified so the appropriate intervention can be taken before a small problem becomes much larger, potentially resulting in pipeline failure and unwanted emissions to the environment.

There are three forms of radiation.

Using techniques applied in oil and gas processing for more than 50 years, many different pipeline scenarios can be determined from outside of the pipeline. The problem arises when the pipeline is buried, as in many subsea applications, and access is difficult. In such case, tracer techniques, similar to the barium used in medical technology, can determine deposit location (and flow regimes). Following are some recent examples of the radioisotope technology; discussions of the scope and limitations of the technology; and indications of the benefits the technology brings to oil and gas operators.

Radioisotope applications Radiation is all around us all the time, whether from natural sources or from manmade devices encountered in everyday life – and contrary to public perceptions of radiation, poses no tangible risk. Examples are: • Naturally occurring radiation in materials such as granite • Cosmic radiation which we receive every time we fly on an airplane • Airport scanners for luggage checks • X-Rays for broken bones • Treatments for illnesses such as cancer. If we use radiation in an pipeline application, an isotope with penetrative power is required to pass through steel pipes or process vessels. Particles of radiation come in three forms: • Alpha particle, which will not pass through paper • Beta particle, which will pass through paper but not steel • Gamma ray particle, which will penetrate steel. Gamma radiation has been used in diagnostic techniques in the oil and gas industry for more than 50 years.

Flow assurance Flow assurance can be defined as the steps required to ensure satisfactory flow from the reservoir to the point of sale, and the desire to understand, map and study the volatile and unpredictable



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(Left) GammaTrac detection unit being deployed subsea. (Right) Multiple units can be deployed when the seabed has significant undulations or depth changes.

oil and gas flow from reservoir. This is a challenge. The uses of medical-based radioisotope techniques in oil and gas flow assurance include the following: • Identify, locate, and quantify materials such as waxes, scales, sand, sludge, and hydrates that block pipelines • Assess total pipeline deposits as part of a cleaning program to increase production • Accurately assess and quantify pipeline condition as per corrosion condition models • Accurately assess and quantify pipeline condition prior to pigging campaign • Identify and locate pipeline restrictions such as stuck pigs • Profile pipeline wax buildup over long time periods • Assess and quantify flow measurements. Liquid and gaseous tracing techniques are used regularly for all of the above in multiphase systems. The tracer is designed to follow a particular material through a system. Sensitive detectors are placed strategically on the outside surface of a pipe (or other process system) where they detect the selected tracer as its flows past. These can directly measure fluid velocity, flow rate, phase distribution, and deposit inventory. By measuring the time between detector responses and knowing the distance between the detectors, the mean linear velocity can be calculated. If full bore turbulent flow can be assumed, then the velocity can be converted to volumetric flow based on the pipe internal diameter. Accuracy depends on the precise circumstances, but the mean velocity usually can be measured to better than +/- 0.5%. The accuracy of the volumetric flow is influenced by the known internal cross sectional area of the pipeline. The basic principle of a tracer investigation is to label a substance or phase and then follow it through the system using suitable detectors. Look at tracer studies from a problem-solving point of view. If problems of fluid transport can be described in terms of “when?”, “where to?”, and “how much?” then they can be solved with tracer techniques. The basic requirements of a tracer are as follows: • It should behave in the same way as the material under investigation • It should be easily detectable at low concentrations • Detection should be unambiguous • Injection and detection should be done without disturbing the studied system

• The residual tracer concentration in the product should be minimal. Frequently, more than one radioisotope will work and the factors that are important in the selection of the tracer are the: • Half life • Specific activity • Type of radiation • Energy of radiation • Physical and chemical form. While tracer studies usually are employed in basic flow measurement, they have also been used successfully in flow assurance to measure the location and extent of solids within a pipeline. In this application, the flow rate through the system must be known and must be kept constant. Detectors are positioned at known distances along the pipeline. A pulse of tracer is added to the pipeline and its velocity past detector positions is measured. Using the velocity and flow rate, the average bore size can be calculated between detector locations. This measurement can give critical information prior to any proposed pigging operations and provides operators with the confidence to successfully run pigging campaigns, knowing a pig will not get stuck and cause significant production losses. This technique is used when the total deposit inventory of long lengths of line needs to be known. Access is not needed to the entire pipeline (it can be buried or subsea), just specific positions for detector location. For example, a recent study of a 110-km (68-mi) pipeline between two offshore platforms was conducted with single measurement positions at each end of the line to give a total deposit inventory of the line. A similar study was conducted with subsea detectors deployed every 10 km (6.2 mi) along a 60-km (37-mi) pipeline to provide information of the total amount of deposit in each 10-km section. The application of the flow assurance technique can be summarized in the flowing steps: • Deploy GammaTrac detection units subsea at known intervals. The units have wireless communication, allowing a permanent deployment subsea to allow for multiple studies. This is especially useful when determining wax build up rates. • The units are deployed at strategic locations. This is critical when the pipeline is laid on a seabed that has many undulations or depth changes. • A suitable radioisotope is injected and its passage is recorded for analysis. On evaluation of the results, the units can be redewww.offshore-mag.com • February 2011 Offshore 105


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(Left) Radioisotope is injected and its passage recorded for analysis. (Right) Data is gathered and evaluated at the worksite, providing instant feedback.

ployed at different locations to provide further more accurate data over shorter distances. • The data is gathered and evaluated by a qualified engineer at the worksite for instant feedback to the client.

Wax build up The tracer study can determine wax build up rates within oil lines such that a pipeline cleaning pigging strategy can be implemented and production increased. By determining an accurate build up rate, both time and money can be saved with any pipeline intervention and cleaning operation. The position and build up of waxes can increase the risk of getting an object (such as a cleaning pig) stuck. The cost of removal and/or recovery of a stuck pig can be significant and is likely to involve many specialist third-party contractors. The lost production time can be expensive, so prevention is preferable to cure.

Hydrate formation Hydrates form within pipeline systems and have a detrimental effect on process operating conditions, resulting in lost production through blockage and restriction. The need to understand where and what size a hydrate plug or restriction is present in the pipeline can assist in getting the pipeline back into full production. In one case, the operator’s gas well started to produce water much earlier than predicted. As such, a standard procedure of injecting methanol was started but production stopped and a hydrate plug was suspected. The operator added a chemical to the line to clear the restriction but a pressure build up indicated the chemical injection had little effect. The real-time, non-intrusive scan of the line showed the pipeline density profile and therefore the hydrate, methanol, chemical, and gas all could be located and monitored during remedial operations.

Conclusion Pipeline deposits The deposit profile within the whole pipeline can be determined by enhancing the above study with the deployment of data gathering units. The case study was for a 70-km (43.5-mi) pipeline with units placed subsea at 15-km (9.3-mi) intervals. A suitable and optimized radioisotope was injected into the pipeline, and led to the discoverey that 6% of the 18% total pipeline deposit volume was contained within a 15-km section. Due to the requirement to pig the line as part of a cleaning program, further investigations were required. The non-intrusive gamma ray transmission technique was deployed. The results showed there were local deposits resulting in only a free volume of 5%. Therefore, a pig would have stuck in the pipeline. Appropriate action was then taken by the client.

Flow profiling Offshore processing is complex and, with ever evolving fields and deeper wells producing more and more three-phase flows, it is imperative that slugging is understood, monitored, and controlled. With an array of in-field flowlines tied back to an FPSO, the need to understand and map slugging is also key for pipeline integrity. With real-time data collection and analysis, a series of in-field flow lines can be accurately measured and monitored. The size and shape of slugs of material can be sent directly to the operations team to alert them to the potential for a process upset. Likewise, long-term slugging effects be detrimental to the pipeline, and hence the data can be used to confirm modeling information.

Radioisotope technology offers powerful and proven techniques to accurately measure the amount and location of pipeline contents such as waxes or hydrate deposits when the pipeline conditions are uncertain. Until recently, these direct, non-intrusive measurements of pipeline contents were thought to be impossible, but many operators have used the technology recently, and its use is rapidly increasing worldwide. The benefits of using tracer and scanning techniques to detect deposits within pipelines are summarized as follows: • The techniques “make process systems transparent.” Rather than guessing at what might be wrong, the techniques allow users to make accurate, informed decisions with respect to further intervention or mitigation. • All techniques provide online and real-time results, allowing optimization and troubleshooting to be performed in-situ. • Small teams of engineers can do the scanning and tracer techniques described above • Most pipeline systems/subsea production systems are complex. But the techniques allow the complexity of the system to be divided into individual components and assessment made of the performance of the individual parts. 

Acknowledgment Based on a paper presented at the Offshore Middle East Conference held Oct. 12-14, 2010, in Doha, Qatar.



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RISK MITIGATION CONSEQUENCE MITIGATION

Preparing for the future of Offshore. JUNE 14-15, 2011

l RIVERSIDE HILTON l NEW ORLEANS, LA

Industry risk management and mitigation professionals will discuss risk factors, risk mitigation, and consequence mitigation in the offshore environment. Speakers will be experts in their respective fields, including risk advisory, insurance, legal, financial, weather, security, and all aspects of offshore operations. Topics to be covered include: · Integrating all risk makers in a company · Prevent the event · Automation risk · Technological and equipment risks · How financial decisions get made

· Risk assessment of contractual agreements · Insurance and financial exposures · Environmental liabilities · Regulatory issues, requirements, changes · Use of safety cases

If you are involved in finance, safety, and operations, Petrosafe Offshore is your premier resource for navigating the industry’s most important risk management challenges.

www.petrosafeoffshore.com Owned & Produced by:

Presented by:

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Online monitoring enhances flow assurance Statoil deploys new system to overcome unique challenges of Vega field

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ew oil and gas field developments are getting more advanced and often include subsea installations, satellite wells, or subsea-to-beach solutions. Long multiphase lines, tie-ins, subseato-beach, and subsea production and processing can pose different operational challenges. One of the most critical challenges is to ensure efficient flow of the produced oil and gas. The Flow Assurance System (FAS) is designed to monitor subsea equipment and well production to give operators necessary information about production content. Subsea hardware now can be equipped with lots of sensors, meters, and advanced instrumentation to provide continuous information about flow conditions. However, there is limited or no instrumentation along the flowline to give needed flow condition data. Thus, operators are forced to rely on multiphase models as virtual measurements. Flow assurance challenges also increase as the flowline length and water depth increase. Other critical situations also can arise, such as equipment failure, wearing down of the choke, and leakage or blockage of pipelines. An adverse situation, such as a flow rate issue or equipment malfunction, can cost the operator time and money and may become an environmental hazard. If changes in normal conditions are detected early, unplanned shut-downs of wells may be avoided. To help operators address flow assurance challenges, FMC developed its FAS system, Flow Manager. The first installation of the online metering included in this system was in 1995. Today, the system meters some 470 oil and gas wells worldwide. As the complexity of the field development increases, online systems require extended functionality. Statoil’s Vega field in the North Sea is one successful FAS example. Statoil uses FAS to manage the unique flow assurance problems presented at Vega field.

Marit Larsen

FMC Technologies

Unique challenges Vega is a gas condensate field near Norway’s west coast. It will be developed as a tie-in to the Gjøa platform with a 167,322-ft (51 km) flowline. The field development covers three reservoirs and is split between two licenses. The subsea layout is an in-line daisy-chain with a four-slot template for each reservoir. Each reservoir will be produced by two wells for a total of six wells in the field. One multiphase meter will be installed on each well and on each template manifold. Statoil’s production strategy for Vega is based on reservoir depletion. Because of the subsea conditions, several operational and flow assurance challenges have been defined by Statoil. These challenges include high reservoir pressure, low temperature during start-up and shut-down, the possibility of hydrate or wax formation, the liquid accumulation effect on ramp-up

time, and the need to operate within safe pressure and temperature margins. Unexpected situations also occur such as failing or reduced performance of the subsea sensors and multiphase flow meters, leakage in the production line and the MEG injection monitoring and control system, or blockage of the production line.

Different modes The main objectives of the Vega FAS are to produce safely and to minimize the shut down/restart periods. In order for the FAS to satisfy the different needs of field production, four different modes were developed. The “Real Time” mode runs in parallel with the real process. It reads sensor values and control parameters from the process control system and automatically adapts the FAS models to the real process. Using the FAS in the Real Time mode, the user has a continuously updated metering, monitoring, and surveillance system. The “Look Ahead” mode of FAS runs in parallel with the Real Time system and continuously simulates the predicted process behavior for a defined time horizon.

Schematic of the subsea installation at Vega.



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:::2))6+25(2,/,1',$&20 ____________________

:::81&219(17,21$/2,/$1'*$6,1',$&20 ________________________________

CALL FOR ABSTRACTS DEADLINE: FEBRUARY 18, 2011 Addressing the needs of the Indian market, the inaugural Offshore India and Unconventional Oil & Gas India is a unique forum for companies interested in the Indian oil and gas industry. A world class conference and rich exhibition of services and equipment will attract decisionmakers eager to meet you and learn what your business offers.

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The Advisory Board for Offshore India and Unconventional Oil & Gas India is now accepting abstracts for the Offshore India and Unconventional Oil & Gas India Conference. We invite you to submit an abstract for this event and share your knowledge, experience and solutions with industry colleagues from around the world. To have your presentation considered for the technical session programme, please submit your 100-400 word abstract by February 18, 2011

FOR FURTHER INFORMATION AND TO SUBMIT YOUR ABSTRACT PLEASE VISIT: WWW.OFFSHOREOILINDIA.COM _________________________ OR WWW.UNCONVENTIONALOILANDGAS-INDIA.COM ________________________________________

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An early indication of potential break-downs of sensors and equipment is crucial to planning maintenance. As such, the Condition Performance Monitoring System monitors the real-time status of subsea sensors, multiphase meters, production chokes, and other flow-related process equipment. To guard against wax build-up and hydrate formation, and for an early indication of leakage and blockage, FMC added the Wax Condition Monitoring, the Hydrate Condition Monitoring, and the Leakage and Blockage Monitoring systems to the Vega FAS.

User interface

Subsea template being installed from crane vessel Thialf. Photo: AndreOsmundsen/Statoil.

It always begins with the current process conditions, and simulates what will happen if the process runs without change. This allows the user to look into the future to get an early warning in time to make any necessary corrective actions. The “What If” simulator may be used to train, analyze, or plan. The purpose of this mode is to run scenarios and analyze the consequences of changing system set points prior to modifications. It also can analyze flow assurance situations that have occurred or are suspected. This mode can improve operational procedures and regularity, such as start-up and ramp-up procedures. The “What If” operating mode is connected to the actual process only indirectly, so it can read the current state in Real Time and use that data as an initial condition for the simulation. “Look Back” mode provides advanced FAS users with a flexible tuning system to adjust the multiphase models in Vega FAS against the Vega field production data. This mode is available in the Web interface.

Functionalities for Vega’s challenges Different Flow Manager systems were used when developing the Vega FAS, which is a customized application that addresses the specific needs of the Vega field operation.

Three subsea templates tieback to Gjøj platform.

The Virtual Flow Metering System measures individual well production rates as a redundancy to the multiphase meters at each wellhead. This virtual metering system does not depend on single sensors or the multiphase meters, so it serves as an accurate back-up to the physical meters. It also calculates pressure and temperatures along the flow path, including downhole and reservoir pressures. The Pipeline Management System monitors the flowline. To counter the long flowline and dynamic behavior associated with Vega, the dynamic multiphase flow simulator OLGA was integrated. This dynamic model enables functionality such as the MEG injection monitoring and control, pig tracking, calculation of liquid accumulation, prediction of flow instabilities, and other transient effects. To achieve optimal ramp-up of wells, manifolds, and pipelines, the Production Choke Control System was included in the Vega FAS. This system recommends flow set points for the production chokes based on operator-defined production targets and constraints. The production strategy contains well-priority, planned gas production, swing wells, and maximum choke openings.

The Vega FAS includes an organized Web-based graphical user interface. This tool includes feature such as process pages that illustrate the field lay-out from the wells through the flowline and into the topside facilities. Output about the flowing conditions such as flow rates, pressures, temperatures, liquid content, and control parameters for the equipment are shown in various positions. Available measurements are integrated into the pages. Other examples include special advice pages configured to show hydrate, wax, pig, and performance monitoring. Typical FAS users are in multiple locations. The control room operator is usually at the Gjøa platform and the production engineer or flow assurance specialist works primarily onshore in the Statoil offices. The Web interface has different access levels to meet the different users’ needs. The Vega FAS’s accessible Web interface gives different users within the Statoil organization a common tool that can improve communication and provide a common understanding about Vega’s production status.

Enhanced decision making Great effort has been put into the flow assurance advisors and the performance monitoring of the subsea production system. Improved measurements and improved field management give increased production. However, it is not the measurements themselves that lead to increased and safe production; it is the interpretation of these measurements. Because of this, a main objective of the Vega FAS is to contribute numbers as well as to provide a better understanding of flow assurance issues as a support for correct decisions. Through the Vega FAS, operators, production engineers, and flow assurance specialists have a tool to monitor the production process, plan for various scenarios, and to give early warnings in time to implement contingency plans. 



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15TH EDITION CONFERENCE & EXHIBITION 15 - 17 MARCH 2011 INTERNATIONAL CONFERENCE CENTRE ACCRA I GHANA

DISCOVER NEW FRONTIERS IN WEST AFRICA

INVITATION TO ATTEND 3[RIH 1EREKIHF]

7YTTSVXIHF]


WWW.OFFSHOREWESTAFRICA.COM

____________________________________


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About Offshore West Africa Responding to the growth, demand and vitality in West Africa’s offshore industry, Offshore West Africa is returning to Ghana for its 2011 conference and exhibition. Offshore West Africa will be held on 15 - 17 March 2011 at the International Conference Centre in Accra, Ghana. In its 15th year of providing a platform for information exchange and new business development, Offshore West Africa is the region’s premier technical forum focused exclusively on West Africa offshore exploration and production activity. Offshore West Africa provides an annual forum that addresses the technical, environmental and business challenges associated with oil and gas exploration and production in West Africa. The conference provides a unique networking opportunity for attendees to share technology and address issues with experts in their respective fields. The Offshore West Africa technical program is developed with the help of an Advisory Board of industry professionals who determine the content of the technical sessions. The conference program will consist of two and one-half days of two concurrent technical session tracks. The sessions will focus on topics such as lessons learned offshore, field development case histories, and deepwater challenges and solutions.

93% of attendees think attending Offshore West Africa is important for meeting business objectives* *Taken from a research study conducted at Offshore West Africa 2010


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Schedule of Events Tuesday 15 March Conference & Exhibition Registration Open Exhibition Opening Plenary Coffee Breaks Operators’ Perspective Lunch Conference Sessions Coffee Breaks Conference Sessions Welcome Reception

08:00 – 18:00 08:30 – 18:00 09:00 – 10:30 10:30 – 11:30 11:30 - 12:30 12:30 – 14:00 14:00 – 15:00 15:00 – 16:00 16:00 – 17:00 17:00 - 18:30

AICC Foyer AICC Foyer & Level 1 Congress Hall Exhibition Floor Congress Hall AICC (Level 1) Conference Rooms 1 & 2 Exhibition Floor Conference Rooms 1 & 2 Exhibition Floor

08:00 – 18:00 08:30 – 18:00 09:30 – 10:30 10:30 – 11:30 11:30 – 12:30 12:30 – 14:00 14:00 – 15:00 15:00 – 16:00 16:00 – 17:00

AICC Foyer AICC Foyer & Level 1 Conference Rooms 1 & 2 Exhibition Floor Conference Rooms 1 & 2 AICC (Level 1) Conference Rooms 1 & 2 Exhibition Floor Conference Rooms 1 & 2

08:00 – 13:30 08:30 – 13:30 09:30 – 11:00 11:00 – 12:00 12:00 – 13:30

AICC Foyer AICC Foyer & Level 1 Conference Room 1 Exhibition Floor AICC (Level 1)

Wednesday 16 March Conference & Exhibition Registration Open Exhibition Conference Sessions Coffee Breaks Conference Sessions Lunch Conference Sessions Coffee Breaks Conference Sessions

Thursday 17 March Conference & Exhibition Registration Open Exhibition Local Content Special Session Coffee Breaks Lunch / Awards Ceremony and Closing Remarks


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Attendance Why Attend Offshore West Africa ? The annual Offshore West Africa Conference and Exhibition 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. • Networking opportunities with a unique audience of the world’s leading executives, managers and engineers from major and independent E&P companies focusing on West Africa’s specific requirements • A world-class two-track technical conference program • An exhibition showcase of technology and capabilities to support improvements in African E&P operations • Expert opinions on the new issues, challenges and solutions associated with the expanding African exploration & production activity

Who Attends Offshore West Africa ? • Integrated oil companies (IOCs) and national oil companies (NOCs) who seek information and emerging technologies in order to plan future operations • Multinational audience of senior executive decision makers from international and regional operators • Service and equipment suppliers • Engineering and construction companies • Contractors and consultants

How to Register Three Ways to Register: • Online: www.offshorewestafrica.com • Fax: Fax completed form to +1 888 299-8057 (U.S. only) or +1 918 831-9161 • Mail: PennWell / OWA 2011, PO Box 973059, Dallas, TX 75397-3059

Register yourself and your colleagues as conference delegates by 14th February and benefit from a €200 Early Bird Discount. For further information please visit www.offshorewestafrica.com.


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Participating Exhibitors include: Exhibitors as of 12th January 2011

ABS

MARINE SUBSEA (UK) LTD

BAKER HUGHES

MODEC INC.

BG TECHNICAL

NESTOIL

CHINA PETROLEUM & PETRO-CHEMICAL EQUIPMENT INDUSTRY ASSOCIATION

OIL AND GAS FREEZONE AUTHORITY

DNV GHANA LTD

OILDATA / XENERGI

DORMAN LONG ENGINEERING LIMITED

PETROLOG

EMERSON PROCESS MANAGEMENT

PETAN

EPIC ATLANTIC LIMITED / COLFAX - ALLWEILER

RICHARDSON OIL & GAS

FURMANITE WEST AFRICA LTD

ROPETEC

FUTURE CONCERNS NIG. LTD.

SEA TRUCKS GROUP

GEOPLEX

TECON

HARDBANDING SOLUTIONS BY POSTLE INDUSTRIES

THE OILTEST GROUP

HALLIBURTON

TILONE SUBSEA LIMITED

INTERMOOR

TOPROPE

LASER

TOTAL

LUKOIL

WEAFRI

MANSFIELD

WORLEYPARSONS ATLANTIC

OILSERV

How to Get There

Venue: Accra International Conference Centre, Castle Road, Accra, Ghana

Directions: From Kokota International Airport (ACC), head southeast on Burma Camp Main Road. Drive along Burma Camp Main Road for approximately 1km, then take a slight right towards Giffard Road. Turn right at Giffard Road and continue for 2.2km. At the roundabout take the 3rd exit onto Liberation Road and continue for 2km. Continue onto the Sankara Overpass and then onto Independence Avenue for 1.7km. At the roundabout take the 3rd exit onto Castle Road and then right again onto Gamel Abdul Nasser Avenue. After 600m turn left, then take a slight right after 400m. Accra International Conference Centre will be on your right hand side.


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6)+-786%8-32*361 15 - 17 MARCH 2011 INTERNATIONAL CONFERENCE CENTRE I ACCRA I GHANA OWAINT11

Please use this promotional code when registering

First Name:

Last Name:

Position: Company: Complete Mailing Address:

Postal code: Country Code:

Telephone:

Fax:

Email:

Registration confirmation will be sent via-email, if a unique email address is provided above.

1. Type of Company or Organization:

2. Job Function:

3. Areas of Interest/Involvement:

10 Oil/Gas company 20 Consulting Company 30 Contractor 40 Engineering/Construction 50 Financial 60 Service/Supply 65 Government/Library/Education 70 Other _______________________________________

02 Management (CEO, Pres.VP)

10 Exploration 39 Financial 01 Production 29 Gas Processing 19 Petrochemical 23 Pipeline/Transportation 05 Drilling 115 Refining 46 Other ___________________________________

05 Engineering/Technical/Geoscience 06 Superintendent/Field Professional/Foreman 10 Purchasing/Consulting 12 Other _______________________________________

4. Purchasing Role: Specify Recommend Approve None For Information on corporate packages, contact Registration Phone: +1 918-831-9160 Email: [email protected]

3 ways to register: Pre-register on line before 9 March 2011. Register on site after 9 March 2011.

1 Fax: Direct: +1 918 831 9161 Toll-Free (US only): +1 888 299 8057

2 Website: www.offshorewestafrica.com

3 Mail: PennWell C&E Registration (OWA) P.O. Box 973059 Dallas, TX 75397-3059 USA For questions please call: Phone: +1 918 831 9160 Toll Free (US only): +1 888 299 8016

Conference Fees: 1. Individual Delegate (Full Conference Registration)* Includes: • Access to all Conference Sessions and Conference Proceedings • Access to the Exhibition Hall • Coffee Breaks in Exhibition Hall • Delegate Lunch on Tuesday, Wednesday and Thursday (Ticketed) • Conference Proceedings

4. African State Oil Companies & Other Government Agencies Includes: • Access to all Conference Sessions • Access to the Exhibition Hall, including Opening & Networking Receptions • Coffee Breaks in Exhibition Hall • Delegate lunch on Tuesday, Wednesday and Thursday (Ticketed) • Conference Proceedings

Paid By 14 February 2011 Paid After 14 February 2011


€ 1,230 € 1,445

2. Corporate Plan (10 delegates)* Includes: • Access to all Conference Sessions • Access to the Exhibition Hall, including Opening & Networking Receptions • Coffee Breaks in Exhibition Hall • Delegate Lunch on Tuesday, Wednesday and Thursday (Ticketed) • Conference Proceedings Paid By 14 February 2011 Paid After 14 February 2011

€ 10,390 € 12,220

3. Exhibitor Delegate (Exhibiting Company’s Only) Exhibit booth staff can upgrade their registration to include access to the conference at a discounted rate

Includes: • • • • • •

Access to all Conference Sessions and Conference Proceedings Access to the Exhibition Hall, including move-in and move-out Access to Opening & Networking Receptions Coffee Breaks in Exhibition Hall Delegate Lunch on Tuesday, Wednesday and Thursday (Ticketed) Conference Proceedings


€ 620 € 725

€ 620 € 725

5. Single Day Conference Delegate Includes: • Access to all Conference Sessions on the corresponding day • Access to the Exhibition Hall, including both the Opening & Networking Receptions • Coffee Breaks in Exhibition Hall • Luncheon on corresponding day (Ticketed) Tuesday Wednesday Thursday

@ € 735 @ € 735 @ € 735

6. Exhibit Visitor Pre-registered visitors FREE (Deadline to pre-register March 9, after March 9 register onsite) Includes: •Access to the Exhibition Hall, including Opening & Networking receptions, Coffee breaks in Exhibition Hall Free before 9 March 2011 Paid after 9 March 2011 € 20 7. Additional Lunch Tickets (for non-delegates) Tuesday Wednesday Thursday

@ € 50/day @ € 50/day @ € 50/day

TOTAL PAYMENT (In Euros only) Payment must be received prior to the conference. If payment is not received by the conference date, the registration fee must be guaranteed on charge card until proof of payment is provided. Make check payable to PennWell/Offshore West Africa 2011.

*Your full-price registration fee includes a one-year paid subscription to Oil & Gas Journal.

Method of Payment: Check enclosed payable to Pennwell/OWA 2011 Wire (Wire information will be provided on invoice) Credit Card: Visa Credit Card Number

Cancellation: Cancellation of registration must be received in writing. Any individual, exhibitor or corporate registrations cancelled before 14 February 2011 will receive a 50% refund of registration fee. After 14 February 2011 no refunds will be permitted. Substitutions may be made at any time by contacting the registration office In writing.

=€

Mastercard

AMEX

Expiry Date

Discover

Full Name (as it appears on card): Card Holder Signature:

Date:

(Required for credit card payment)


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CONFERENCE & EXHIBITION

July 19 - 21, 2011 Calgary TELUS Convention Centre Calgary, Alberta | Canada www.oilsandstechnologies.com

every drop counts Now moving from recovery to expansion, the Canadian oil sands industry is an increasingly important source of oil supply and a breeding ground for technologies crucial to the environmentally responsible development of unconventional resources around the world. The Oil Sands and Heavy Oil Technologies Conference & Exhibition examines challenges, innovations and advances in this vital area. It’s the industry’s premier forum for new developments in areas such as production efficiency, drilling methods, environmental remediation, cost control, power supply, geophysical techniques, water management, and by-products handling. Don’t miss the chance to showcase your latest technologies to influential decision makers at this important event. For further information and to register online visit www.oilsandstechnologies.com. Please use this Promotional Code when registering: OS20111




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BUSINESS BRIEFS

People MCS Kenny has appointed Steven Bernard as VP of riser delivery. Bernard’s primary role will be supporting the growth of MCS Kenny, with a focus on expanding riser delivery services to the offshore Bernard industry. Cosalt Offshore has appointed Rod Buchan as CEO. Badger Explorer has appointed Dr. Wolfgang Mathis as product manager. Iran’s Minister of Petroleum Dr. Seyed Masoud Horstmann Mirkazemi has named Mousa Souri as the new MD of Pars Oil and Gas Co. He was previously MD of the Pars Special Energy Zone and the Iranian Oil Terminals Co. Multi-Chem has appointed Dennis Horstmann as manager of global Spratt business development and Tony Spratt as manager of CAPEX and flow assurance technology. InterMoor has named Ross Landry as subsea operations manager. Working out of InterMoor’s Lafayette, Louisiana, facilLandry ity, Landry will manage all activities related to subsea operations including but not limited to abrasive cutting services, heave compensation services, and all facility-based projects. Kjell E. Jacobsen has resigned from the Seadrill Ltd. board of directors and Carl Erik Steen is nominated to fill his place. Lifting, tooling, and marine services provider Cosalt Offshore has appointed Runar Blakstad managing director of its Norway division. Clough Ltd. has appointed Nick White as director of processing engineering. White reports to Bary Bowtell, executive VP, Engineering. InterMoor has named Sarah Kawas as business development manager–Latin America. With 13 years of industry experience, Kawas also has experience in technical sales, marketing, and project management. Beach Energy Ltd. has appointed Gordon Moseby, GM–business review and planning, as a director of its subsidiaries Australian Petroleum Investments Pty Ltd., Delhi Petro-

leum Pty Ltd (Delhi), and Delhi Holdings Pty Ltd.. GE Oil & Gas has appointed Andrew Way as VP of services. Way will be responsible for leading continued growth of the business’ equipment repair, maintenance, upgrade, and remote monitoring and diagnostics capabilities across all segments of the oil and gas industry. Foster Marketing Communications has appointed Bob Lytle as account supervisor in the firm’s Houston office. Lytle has more than 30 years’ experience in marketing communications. Rowan Companies Inc. has appointed Suzanne P. Nimocks to its board of directors. Nimocks recently retired from McKinsey & Co. Inc., where she served as a director (senior partner) from June 1999 to March 2010. Ikon Science has appointed Richard Swarbrick as global director of geopressure. Swarbrick also becomes a member of the company’s board. Coretrax Technology has appointed Chris Calder as operations manager to oversee the facilities in Aberdeen and service delivery to customers worldwide. C & C Technologies has appointed Ralph Coleman as VP of marine construction surveys. Jason Duplechin has been promoted to manager of the spatial data management department. Eric Granger has been appointed marine construction operations manager and will continue managing C & C’s offshore survey crews. Jake Klara has been named senior VP of international operations and strategic development. Klara will concentrate on marine construction opportunities and new technologies. Dean White has joined C & C as its marine department manager. White will work to further improve the quality and professionalism of C & C’s vessel operations. ABS has named Todd Grove as chief technology officer. John McDonald, currently regional VP, Northern Europe and Africa, will succeed Grove as president and COO of the ABS Europe Division. John Gallagher, currently regional VP, North America, will transfer to London and assume the position of regional VP, Northern Europe. Thomas Blenk, currently VP of global operations, ABS Nautical Systems (NS) Division, will transfer to New York City and replace Gallagher. Demetri Stroubakis, currently regional VP, Eastern Europe, will transfer to Houston and replace Blenk. Vassilios Kroustallis, currently country manager for Greece, will replace Stroubakis. Christos Nomikos, currently principal surveyor for Greece, will replace Kroustallis. All changes are effective Feb. 1. Atwood Oceanics Inc. has appointed Arthur M. Polhamus as VP of Operations starting Feb. 1. Qatar has appointed Mohammed Saleh al-Sada as its new energy minister. Al-Sada

has been managing director of state-owned RasGas, which has a partnership with Exxon Mobil. He replaces Abdullah bin Hamad alAttiyah, who remains deputy prime minister. Mustang has appointed Gordon Stirling as regional director for Europe, North Africa, Middle East, India, and Russia. The company has also named Chet Nelson as regional director for Asia-Pacific. The regional directors Nelson will facilitate and direct business activities for all markets served by Mustang, providing for efficient and coordinated operations across all of the company’s business units. W&T Offshore has appointed Jesus G. MelenStirling drez as senior VP and chief commercial officer. Transocean has appointed Nick Deeming as senior VP, general counsel, and assistant corporate secretary, effective Feb. 7. Eric B. Brown, currently in that role, will transition to the company’s Houston office, primarily leading the company’s Macondo litigation efforts. Bahamas Petroleum has named Dr. Paul Crevello CEO. He replaces Alan Burns, who will remain as non-executive chairman of the company. ERM has appointed Maximo Hernandez as global oil and gas managing partner. Hernandez will develop and lead ERM’s strategies in oil and gas and support consultants as they advise major clients on the impacts and alternatives resulting from the rapidly changing environment.

Company News InterMoor has opened a new 24-acre facility in Morgan City, Louisiana. This ISO9001:2008 approved site contains a fabrication facility that includes two fabrication buildings, both with capabilities to design and produce comprehensive offshore mooring systems, subsea foundations, and equipment. EnerMech has invested $31.5 million in a new Process, Pipeline, and Umbilical Services division. The commitment includes an initial £2.7 million ($4.3 million) outlay on on-site machining and hydraulic bolting and tensioning equipment. More will be invested in nitrogen convertors (ATEX, DNV, Zoned), nitrogen liquid storage tanks, fluid pumping equipment, subsea flooding and testing packages, air compressors, and nitrogen membrane units, the company says. Energy Partners Ltd. (EPL) has acquired producing oil and natural gas assets in the shallow-water central Gulf of Mexico shelf



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BUSINESS BRIEFS

from Anglo-Suisse Offshore Partners for $201.5 million. The assets currently produce approximately 3,000 net boe/d about 92% of which is oil. The properties include three main complexes and field areas in Main Pass blocks 296/301/311, South Pass blocks 33/49, and West Delta blocks 26/27/28/29/47 on the GoM shelf, in the vicinity of EPL’s existing South Timbalier and East Bay operations. HB Rentals has agreed to supply accommodation units on the BP Regalia platform on the Valhall field. Under the 18-month contract, the company will supply four A60, Zone II NORSOK-compliant office modules. UK North Sea operator has completed a strategic review of its assets. Shareholders have approved the resultant business plan, agreeing in principle to provide a further $150 million to fund future growth opportunities. Technip has awarded DOF Subsea UK a contract for the provision of the light construction vessel Geoholm in the North Sea. The work is scheduled to start in the second quarter and to take place in 2011 and 2012 using two onboard WROVs. Petrofac has awarded Champion Technologies a two-year contract. The contract scope covers a full range of production chemicals and associated management services for the Heather, Thistle, Northern Producer, and Kittiwake installations in the North Sea.

Reef Subsea AS has acquired EXS Subsea AS, which owns 80% in S3, Specialist Subsea Services Ltd. S3 specializes in offshore survey, positioning, and ROV services. Services include remote intervention, IMR, construction support, seabed mapping, geophysical surveys, geotechnical services, survey data presentation and data management. McMoRan Exploration Co. has completed acquisition of Plains Exploration & Production Co.’s shallow-water Gulf of Mexico shelf properties. PXP received $86 million in cash and 51 million shares of McMoRan common stock in exchange for all its GoM leases in less than 500 ft (152 m) of water. Gulfsands Petroleum plc has announced the sale of three properties from the Company’s Gulf of Mexico asset portfolio. These noncore producing properties are located in the shallow-water shelf area of the Gulf of Mexico, and the disposal is a part of the company’s ongoing plans to rationalize its US oil and gas property portfolio. The properties include various working interests in the Eugene Island 57/58 (EI 57/58) gas field, the Vermillion 379 (VR 379) oil and gas field and the South Pelto 13 (PL13) oil and gas field. Statoil has agreed to acquire Marathon Petroleum Norway’s 20% interest in Gudrun and 12.5% interest in Eirin on the Norwegian continental shelf. Statoil increases its holding

from 55% to 75% in production licenses 025 and 187 in the North Sea which cover the Gudrun field currently under development and the Sigrun and Brynhild discoveries. Statoil is also acquiring a 12.5% interest in the Eirin discovery in production license 048E. Toll Mermaid Logistic Broome Pty Ltd. has added capacity at its Broome supply base to serve Browse basin operators. Mermaid Marine Australia is set to work the offshore operations while Toll Energy’s logistics experience work onshore. Seatronics has entered a master services agreement with Oceaneering International Inc. Under the agreement, Seatronics’ rental inventory will be enhanced by a range of ROV tools belonging to Oceaneering’s Deepwater Technical Services (DTS) division. Promperforator has agreed to distribute Titan Specialties’ products in Russia, Turkmenistan, Kazakhstan, Azerbaijan, Belarus, Ukraine, Uzbekistan, Armenia, Kyrgyzstan, Moldova, and Tajikistan. HB Rentals has opened a location in Dubai operating under its parent company, Superior Energy Services. Daewoo Shipping and Marine Engineering (DSME) has awarded Alliance Engineering a contract to provide jacket and topsides engineering and design for Chevron’s South Nemba Auxiliary (SNX) project in Angola’s Nemba field.

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

• Display Ads: $235.00 per column inch. Same discount as above. 15% agency commission. $235.00 minimum charge for insertions. Page size is 3 columns wide by 10 inches deep. One Column = 2.25” wide, Two Columns = 4.75” wide, Three Columns = 7” wide. Minimum Size: 1 Column X 1 Inch. • Deadline for classified advertising is the 15th of the month preceding publication. Contact Glenda Harp, (918) 832-9301, or fax your ad for a quote (918) 832-9201. E-mail: [email protected] • No special position available in classified.

C O N S U LTA N T S

C O N S U LTA N T S

Brazil: EXPETRO can be your guide into this new investment frontier. Effective strategic analysis, quality technical services, compelling economic/regulatory advice, and realistic approach regarding Brazilian business environment - 120 specialists upstream, downstream, gas and biofuels. Email: [email protected] Web: www.expetro.com.br -Rio de Janeiro, Brazil

EMPLOYMENT

Got jobs? We’ve got people.

Your connection to the energy industry’s top career-minded professionals. | Learn More | Visit: www.PennEnergyJOBS.com Call: 1-800-738-0134

Hiring? Selling Equipment? Need Equipment? CONTACT: GLENDA HARP +1-918-832-9301 or 1-800-331-4463, Ext. 6301 Fax: +1-918-832-9201 Email: [email protected]



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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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2011/2012 PETROLEUM EVENTS CALENDAR

Subsea Tieback Forum & Exhibition February 22 – 24, 2011 San Antonio, Texas USA Website: www.subseatiebackforum.com

Offshore India Unconventional Oil & Gas India Conference & Exhibition September 14-16, 2011 Mumbai, India

Offshore West Africa Conference & Exhibition March 15 – 17, 2011 Accra, Ghana Website: www.offshorewestafrica.com

Oil & Gas Maintenance Technology North America Conference & Exhibition September 20-22, 2011 Galveston, Texas USA Website: www.ogmtna.com

Offshore Asia Conference & Exhibition March 29 – 31, 2011 Singapore Website: www.offshoreasiaevent.com Petrosafe Offshore Conference June 14 – 15, 2011 New Orleans, Louisiana USA Website: www.petrosafeoffshore.com Oil Sands and Heavy Oil Technologies Conference & Exhibition July 19 – 21, 2011 Calgary, Alberta, Canada Website: www.oilsandstechnologies.com

Deep Offshore Technology International Conference & Exhibition October 11 – 13, 2011 New Orleans, Louisiana USA Website: deepoffshoretechnology.com Deepwater Operations Conference & Exhibition November 1 – 3, 2011 Galveston, Texas USA Website: www.deepwateroperations.com Topsides, Platforms & Hulls Conference & Exhibition January 31-February 2, 2012 New Orleans, Louisiana USA Website: www.topsidesevent.com

Unconventional Oil & Gas International Conference & Exhibition August 29 – 31, 2011 San Antonio, Texas USA Website: www.unconventionaloilgas.com


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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] 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] 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]

AADE National Technical Conference & Exhibition ...................................................89 www.aade.org Aker Solutions ......................................... 2-3 www.akersolutions.com/subsea American Petroleum Institute ...................81 www.api.org Australian Petroleum Production & Exploration Association ............................96 www.appea.com.au Balmoral Group, Ltd. .................................83 www.balmoral-group.com Bredero Shaw...............................................9 www.brederoshaw.com Brunswick Commercial & Government Products .....................................................58 www.brunswickcgp.com Cameron .....................................................13 www.c-a-m.com/fastrac Cameron .....................................................31 www.c-a-m.com CapRock Communications .......................59 www.caprock.com Clariant Oil Services..................................73 www.clariant.com Co. L. Mar. S.r.l. ..........................................82 www.colmaritalia.it Cortec Fluid Control ..................................79 www.uscortec.com CRC-Evans Automatic Welding ................54 www.crc-evans.com CUDD Energy Services .............................45 www.cuddpressurecntrl.com Delta Rigging & Tools ................................21 www.deltarigging.com Dril-Quip ..................................................... 11 www.dril-quip.com Emerson Process Management .................5 EmersonProcess.com/Deepwater FMC Technologies........ ............................ C2 www.fmctechnologies.com GE Oil & Gas........ ......................................41 www.geoilandgas.com Global Industries........ ...............................33 www.globalind.com Government of Newfoundland and Labrador........ .............................................63 www.gov.nf.ca Hydratight........ ...........................................60 www.hydratight.com Hytorc....................................................85, 87 www.hytorc.com INTECSEA ..................................................61 www.INTECSEA.com/careers Intermoor ....................................................40 www.intermoor.com J. Ray McDermott.......................................47 www.mcdermott.com Karmsund Maritime Offshore Supply.......64 www.kamos.no KOBELCO / Kobe Steel Ltd....... ................37 www.kobelcoedti.com www.kobelco.co.jp Liebherr-Werk Nenzing GmbH.. ................42 www.liebherr.com L & M Radiator.. .........................................38 www.mesabi.com M-I Swaco. ..................................................19 www.miswaco.com McCoy Drilling & Completions .................51 www.mccoyglobal.com National Oilwell Varco................................15 www.nov.com/qualitytubing National Oilwell Varco................................27 www.nov.com Newpark Drilling Fluids.. ...........................17 www.newparkdf.com

Nylacast .. ...................................................10 www.nylacast.com Oil and Gas Asia 2011 .. .............................91 www.oilandgas-asia.com Olaer Benelux BV ......................................48 www.olaer.nl Orion Instruments .....................................43 www.orioninstruments.com Orr Safety Corporation .. ...........................75 www.orrsafety.com/kong Pacific Drilling.. ..........................................16 www.pacificdrilling.com PennWell Deep Offshore Technology...................93 www.deepoffshoretechnology.com Offshore Asia Conference & Exhibition ..............................................95 www.offshoreasiaevent.com Offshore India Conference & Exhibition ............................................109 www.offshoreoilindia.com Offshore Webcasts ...............................77 www.offshore-mag.com Offshore West Africa Conference & Exhibition ................................ 65, 111-116 www.offshorewestafrica.com OGMTNA Conference & Exhibition ...121 www.ogmtna.com Oil Sands and Heavy Oil Technolgies Conference & Exhibition .................... 117 www.oilsandtechnologies.com PennEnergy Research ........................ 119 www.PennEnergy.com/index/conference.html

Petrosafe Offshore Conference & Exhibition ............................................107 www.petrosafeoffshore.com Subsea Tieback Forum & Exhibition ..............................................53 www.subseatiebackforum.com Postle Industries, Inc. ................................50 www.postle.com RM Young Company ..................................60 www.youngusa.com Schlumberger ........................................... C4 www.slb.com Sea Trucks Group ......................................67 www.seatrucksgroup.com ShawCor .....................................................29 www.shawcor.com Siemens ......................................................53 www.siemens.com Subsea 7 .....................................................25 www.subsea7.com TD Williamson, Inc. ................................... C3 www.tdwilliamson.com Tesco Corporation .....................................49 www.tescocorp.com Tetra Technologies, Inc. ............................18 www.tetratec.com Transocean........ ...........................................1 www.deepwater.com Vallourec & Mannesmann Tubes ..............57 www.vmtubes.com Versabar, Inc.........................................35, 71 www.vbar.com Wasco Energy Group of Companies........44 www.wascoenergy.com Weatherford..............................................6, 7 weatherford.com Wild Well Control .......................................39 www.wildwell.com Williamson and Rusnak ............................23 www.jimmywilliamson.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

Environmental, social compliance key to success in Southeast Asia As in much of the world, governments in Southeast Asia want hydrocarbon development, but want it done in a way that protects their environment, economy, and social structure. In offshore work, this can mean impacts on: • Environmental issues, such as marine mammals, that may be affected by noise from activities like pile driving • Social issues, including the effect that a shore base may have on life in nearby villages • Economic issues, such as the effect of a project on subsistence fishing by local people. Companies that fail to heed regulations and expectations may find their projects delayed, costs increased, and future projects in jeopardy. This means that being able to meet Environmental, Health, and Safety (EHS) regulations – with the social implications of projects becoming more important – is as much a success factor as good seismic interpretation and reservoir production strategy. While many of the largest global companies are already well resourced in EHS compliance, we find the greatest need for improvement in the mid-sized companies from outside the region. Experience shows that, as with oil and gas exploration and production, two of the most critical elements of success in EHS compliance are management of timelines and obtaining the right skills. This is true everywhere, but the complex and fluid nature of the regulatory environment in Southeast Asia makes this even more critical.

The right skills Having provided consultation to resource companies and professional services firms, it seems that members of the resource sector need the best of both worlds – knowledge of the local situation backed by best practices globally. This is best found in the large, international firms that are able to provide skilled professionals with local expertise. Regulators take comfort in the business processes and procedures adhered to by these larger firms, and this can mean a faster, smoother approvals process. In any business center in Southeast Asia, there are local firms with significant local expertise and the ability to get results. It may be best for resource companies to access their skills indirectly, through the international firms with which they partner. As in many business situations, the question is whether to develop the necessary capabilities internally, or develop them outside. Resource companies of all sizes should develop enough understanding of the process to understand when it is being done well, but midsize and smaller companies in particular are better off developing a relationship with a credible external resource when it comes to EHS compliance. Local knowledge is particularly important in Southeast Asia. For example, a state oil company may have its own reasons for pressing a resource company to use a particular seaport as its main access to the country, while a qualified professional advisory firm may from its experience know that its infrastructure is not adequate, and that the company should insist on using a different port.

Factoring in compliance Trying to rush a seismic or exploratory drilling program can have severe consequences in mistakes and higher costs. It is the same with EHS compliance. Companies need to build their understanding of their legal obligations, such as having the necessary EHS permits. If they do not comply, regulators may respond with questions and challenges that take time to answer – perhaps the baseline data is insufficient, or impacts of the project on shipping traffic have not been adequately addressed. As a result, the approval may take longer than if sufficient time had been budgeted. One of the challenges of working in Southeast Asia is that, particularly in some countries such as Vietnam, regulations are always evolving and are further defined by circulars and decrees. Finding out the applicable regulations may add to the timeline. While many international oil and gas companies say – and believe – that they have allowed enough time for EHS regulatory compliance, many of the regulatory problems are because companies do not understand the local requirements and do not allow enough time.

Other considerations In Southeast Asia, most oil and gas endeavors involve a joint venture that involves a state oil company. Sometimes these state companies have ideas on the priority to be placed on environmental health and safety that are different from the international norm followed by Western-based resource companies. While dependent on the goodwill of the state-owned company, the Western companies may need to put a good deal of effort into helping their partner company meet the Western company’s internal requirements, as well as those of shareholders, non-governmental organizations, and their own financial backers.

Rob Kirk

Golder Associates, Singapore

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].

124 Offshore February 2011 • www.offshore-mag.com ___________


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