Test Mag by John Goodnight

Houston

London

Paris

Stavanger

Aberdeen

Singapore

Moscow

Baku

Perth

Rio de Janeiro

Lagos

Luanda

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

February 2009

World Trends and Technology for Offshore Oil and Gas Operations

BPâ&#x20AC;&#x2122;s Thunder Horse pushing the technology frontier

Rig market adjusts to economy, oil price Qatar ďŹ eld optimized with multi-lateral wells : DE Asia w I S e e IN hor revi fs p Of ow sh 0902off_C1 C1

2/11/09 2:02:31 PM

Break

perfo at a reco

2 mil FMC’s new Enhanced Vertical Deepwater pwater Tree (EVDT) just set a new depth record at Shell’s Perdido project in the Gulf of Mexico: co: 9,356 feet o is EVDT’s (2,852 m). That’s impressive, but so ntages of performance: It combines the advantages design capacity. with larg duction slimbore design with large bore production ng hanger in It’s versatile – you can land the tubing the subsea wellhead or in the tubingg head. And you can install it with a conventional rigg equipped with a surface BOP, for big savings. Which h makes EVDT a great choice at any depth.

0902off_C2 C2

2/11/09 1:55:31 PM

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𰁖𰁍𰁋𰀄𰁓𰁙𰁖𰀄𰁇𰁙𰁗𰁘𰁓𰁑𰁉𰁖𰁗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𰁍𰁒𰀄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

0902off_1 1

2/11/09 1:55:56 PM

Well plugging and abandonment / Platform removal / Environmental and regulatory consultancy / Subsea well abandonment / Rigless well abandonment / Structural severance / Retrieval of flexible pipeline and mooring equipment

0902off_2 2

2/11/09 1:55:57 PM

DECOMMISSIONING Acteon companies have contributed to a wide range of demanding projects over many years involving the abandonment and decommissioning of platform and subsea wells and their associated production facilities. Talk to us about the provision of specialist services, or when you are looking for someone to direct the entire decommissioning process. For more information about how Acteon companies can help you to overcome your decommissioning challenges, visit

www.acteon.com

0902off_3 3

2/11/09 1:56:00 PM

International Edition Volume 69, Number 2 February 2009 Celebrating Over 50 Years of Trends, Tools, and Technology

CONTENTS

ASIA Miocene/basement fairway opens up alongside Bach Ho ........................................ 48 Output is building at the Ca Ngu Vang, the ﬁrst ﬁeld in Vietnam’s Cuu Long basin to be developed as a third-party tieback to the Bach Ho offshore complex.

Offshore Asia 2009 ..................................................................................................... 56 The 2009 Offshore Asia Conference & Exhibition will take place March 31-April 2, 2009 at the IMPACT Exhibition and Conference Center in Bangkok, Thailand. The Department of Mineral Fuels, Ministry of Energy, Thailand, has endorsed the conference, and PTT Exploration and Production Plc. (PTTEP) will be hosting.

Intensive five-year drilling campaign to lift production from Bohai Bay fields ....... 62 ROC Oil is strengthening its position as the fourth-ranked foreign operator of oil production in China. The Sydney-based company, active in the country since 2002, is midway through a program to expand and to extend production from the Zhao Dong fields in Bohai Bay.

GEOLOGY & GEOPHYSICS BPC re-assessing potential of southern Bahamas play............................................ 66

46 TOP 10 DRILLING CONTRACTORS Rig market adjusts to economy, oil price .......................... 32 While the downturn in the global ﬁnancial markets is having an effect on just about every aspect of business around the world, the most important inﬂuence in the realm of petroleum remains the price of oil.

Global offshore prospects remain strong ..................................... 38 We have just lived through the most volatile year in the history of the oil industry, with spectacular highs and crashing lows. After such a tumultuous year, what can we expect in 2009?

SPECIAL REPORT Thunder Horse: Pushing the technology frontier ....................... 42 In December 2008, BP successfully started production from the third and fourth wells at the Thunder Horse South ﬁeld in the US Gulf of Mexico with production in excess of 200,000 boe/d.

The revival of exploration off northern Cuba has rekindled interest in the Bahamas. Although no wells have been drilled off the islands since 1986, new geological studies suggest strong analogies among producing provinces from Cuba and southern Florida to giant ﬁelds such as Cantarell in the southern Gulf of Mexico.

Life-of-field seismic system adds value to reservoir simulation of Valhall field .... 70 The frequent time-lapse observations from the Life of Field Seismic (LoFS) system across the Valhall field have provided a wealth of information. The production and injection responses can be observed through time-shift and amplitude changes.

DRILLING & COMPLETION Project offshore Qatar extends horizontal drilling limits .......................................... 74 Maersk Oil Qatar is operator of Al Shaheen ﬁeld on the central axis of the Qatar Arch some 70 km (43.5 mi) northeast of the Qatar peninsula. The main production targets are the Lower Cretaceous Kharaib B and Shuaiba carbonate formations and the Nahr Umr sandstone.

Despite equipment limitations in the region, India’s Jindal Drilling steps forward ......................................................................... 80 India’s Jindal Drilling & Industries Ltd. is intensifying efforts to introduce new technologies to the sub-continental’s fast expanding quantity of hydrocarbon prospecting acreage.

PRODUCTION OPERATIONS Aker monohulls to take on wider range of intervention tasks ................................. 84 A step-change in subsea well intervention is imminent. Aker Oilﬁeld Services has ordered four newbuild vessels to extend the range of services it plans to offer. The ﬁrst, due for delivery in early 2010, already has a long-term contract with Petrobras.

Offshore (ISSN 0030-0608) is published monthly by PennWell, 1421 S. Sheridan Road, Tulsa, OK 74112. Periodicals class postage paid at Tulsa, OK, and additional offices. Copyright 2009 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. Ride-Along enclosed, version P1 & P2.

0902off_4 4

2/11/09 2:06:49 PM

World-class communications anywhere in the world â&#x201E;˘

With its advanced, global satellite network, CapRock Communications delivers business-grade communications to virtually any point on Earth. No matter how far offshore or how challenging the environment, you ll get the same quality communications that you d find at your corporate headquarters.

Available as a standard service package or a custom-developed network, CapRock satellite solutions include telephone, fax, e-mail, Internet, video and secure networking. Thanks to more than 25 years of experience, world-leading reliability and global satellite coverage, we bring the services you ve come to expect to places you wouldn t

Voice over IP

expect to find them.

Secure Corporate Networking Broadband Internet Real-Time Video w w w. C a p R o c k . c o m

R E L I A B I L I T Y T O T H E E X T R E M Eâ&#x201E;˘

0902off_5 5

2/11/09 2:06:55 PM

International Edition Volume 69, Number 2 February 2009

𰀧𰀰𰀳𰀨𰀪𰀯𰀨𰀁𰀴𰀰𰀭𰀶𰀵𰀪𰀰𰀯𰀴𰀧𰀰𰀳𰀁𰀩𰀪𰀨𰀩𰀁𰀱𰀳𰀦𰀴𰀴𰀶𰀳𰀦𰀁𰀴𰀪𰀵𰀶𰀢𰀵𰀪𰀰𰀯𰀴𰀏𰀸𰁉𰁆𰁏𰀁𰁅𰁓𰁊𰁍𰁍𰁊𰁏𰁈𰀁𰁖𰁏𰁅𰁆𰁓𰀁𰁉𰁂𰁓𰁔𰁉𰀁𰁄𰁐𰁏𰁅𰁊𰁕𰁊𰁐𰁏𰁔𰀍𰀁𰁚𰁐𰁖𰀁𰁏𰁆𰁆𰁅𰀁𰁖𰁏𰁄𰁐𰁎𰁑𰁓𰁐𰁎𰁊𰁔𰁊𰁏𰁈𰀁𰁒𰁖𰁂𰁍𰁊𰁕𰁚𰀁𰁇𰁓𰁐𰁎𰁚𰁐𰁖𰁓𰀁𰁗𰁂𰁍𰁗𰁆𰀁𰁃𰁐𰁅𰁊𰁆𰁔𰀍𰀁𰁍𰁂𰁕𰁆𰁓𰁂𰁍𰁔𰀍𰀁𰁕𰁆𰁆𰁔𰀍𰀁𰁄𰁓𰁐𰁔𰁔𰁆𰁔𰀍𰀁𰁂𰁏𰁅𰀁𰁖𰁏𰁊𰁐𰁏𰁔𰀏𰀁𰀺𰁐𰁖𰀁𰁏𰁆𰁆𰁅𰀁𰀤𰁍𰁊𰁇𰁇𰁐𰁓𰁅𰀎𰀫𰁂𰁄𰁐𰁃𰁔𰀁𰀧𰁐𰁓𰁈𰁊𰁏𰁈𰂱𰁂𰀁𰁍𰁆𰁂𰁅𰁆𰁓𰀁𰁊𰁏𰀁𰁍𰁐𰁘𰀎𰁕𰁐𰀎𰁎𰁆𰁅𰁊𰁖𰁎𰀁𰁓𰁖𰁏𰁔𰀁𰁐𰁇𰀁𰁐𰁊𰁍𰁇𰁊𰁆𰁍𰁅𰀁𰁇𰁐𰁓𰁈𰁊𰁏𰁈𰁔𰀏𰀷𰁊𰁔𰁊𰁕𰀁𰁘𰁘𰁘𰀏𰁄𰁍𰁊𰁇𰁇𰁐𰁓𰁅𰀎𰁋𰁂𰁄𰁐𰁃𰁔𰀏𰁄𰁐𰁎𰀍𰁐𰁓𰀁𰁄𰁂𰁍𰁍𰀁𰀓𰀒𰀘𰀏𰀔𰀖𰀔𰀏𰀖𰀒𰀘𰀓𰀁𰁕𰁐𰀁𰁍𰁆𰁂𰁓𰁏𰀁𰁎𰁐𰁓𰁆𰀏

COVER: In December 2008, BP successfully started production from the third and fourth wells at the Thunder Horse South field in the US Gulf of Mexico with production in excess of 200,000 boe/d. The field’s productiondrilling-quarters (PDQ) semisubmersible pictured here, in 6,000 ft (1,829 m) of water about 150 mi (241 km) offshore, is the largest production semi ever built with a total displacement of 130,000 tons (117,934 metric tons). The topsides area is the size of three football fields. The development of Thunder Horse has driven the creation and evolution of many technologies. Read the full story, exclusively for Offshore, beginning on page 42. Photo credit: 2008 BP Imageshop/Marc Morrison.

SUBSEA Challenges of the Jansz deepwater tieback ............................................................. 88 Large diameter, deepwater pipelines are a signiﬁcant part of total project cost, so optimizing routes was required from both installation and operations cost viewpoints for both the Gorgon and deepwater Jansz ﬁelds off the northwest coast of Barrow Island, Western Australia.

FLOWLINES & PIPELINE How to overcome challenges with active electrical heating in deepwater ............. 90 Electrical heating of thermal insulated pipelines to prevent hydrate formation and wax deposition in subsea oil production has proven to be technically and economically viable in shallow water applications.

EQUIPMENT & ENGINEERING Open bore wellhead system key to deep wells in deepwater .................................. 94 As offshore wells are drilled in deeper water to deeper depths around the world, the selection of a subsea wellhead system remains a critical factor in meeting the drilling challenges.

D E P A R T M E N T S CLIFFORD-JACOBS

FORGING 𰀱𰀏𰀰𰀏𰀁𰀣𰁐𰁙𰀁𰀙𰀔𰀑𰀁𰀤𰁉𰁂𰁎𰁑𰁂𰁊𰁈𰁏𰀍𰀁𰀪𰀭𰀁𰀗𰀒𰀙𰀓𰀕𰀎𰀑𰀙𰀔𰀑𰀁𰀁𰀓𰀒𰀘𰀏𰀔𰀖𰀓𰀏𰀖𰀒𰀘𰀓𰀁𰀁𰁇𰁂𰁙𰀛𰀁𰀓𰀒𰀘𰀏𰀔𰀖𰀓𰀏𰀕𰀗𰀓𰀚𰁔𰁂𰁍𰁆𰁔𰀡𰁄𰁍𰁊𰁇𰁇𰁐𰁓𰁅𰀎𰁋𰁂𰁄𰁐𰁃𰁔𰀏𰁄𰁐𰁎

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

Vessels, Rigs & Surface Systems ....... 24 Drilling & Production .......................... 28 Geosciences ........................................ 30 Business Briefs ................................... 96 Advertisers’ Index............................... 99 Beyond the Horizon .......................... 100

𰀪𰀴𰀰𰀁𰀚𰀑𰀑𰀒𰀛𰀓𰀑𰀑𰀑𰀁𰀤𰀦𰀳𰀵𰀪𰀧𰀪𰀦𰀥

0902off_6 6

2/11/09 2:06:55 PM

0902off_7 7

2/11/09 2:06:59 PM

COMMENT

Eldon Ball • Houston

PennWell

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

VICE PRESIDENT and GROUP PUBLISHER John Royall johnr@pennwell.com

EDITOR-IN-CHIEF

MANAGING EDITOR

Eldon R. Ball eldonb@pennwell.com

David Paganie davidp@pennwell.com

EDITOR-EUROPE

TECHNOLOGY EDITOR, SUBSEA & SEISMIC

Jeremy Beckman jeremyb@pennwell.com

EDITORIAL ASSISTANT

Gene Kliewer genek@pennwell.com

Priti Ubhayakar pritiu@pennwell.com

TECHNOLOGY EDITOR, DRILLING & PRODUCTION

PRESENTATION EDITOR

John Waggoner jwaggoner@pennwell.com

Josh Troutman josht@pennwell.com

CONTRIBUTING EDITORS Nick Terdre (Norway) David Shields (Mexico) Peter Howard Wertheim (Brazil) Gurdip Singh (Singapore)

SALES WORLDWIDE SALES MANAGER HOUSTON AREA SALES David Davis davidd@pennwell.com Tel: (713) 963-6206 Bailey Simpson baileys@pennwell.com

CUSTOM PUBLISHING Roy Markum roym@pennwell.com Tel: (713) 963-6220

PRODUCTION MANAGER Rae Lynn Cooper raec@pennwell.com Tel: (918) 831-9143 • Fax: (918) 831-9415

AUDIENCE DEVELOPMENT MANAGER Tommie Grigg tommieg@pennwell.com Tel: (918) 832-9207 • Fax: (918) 831-9482

SUBSCRIBER SERVICES Contact subscriber services for address changes Tel: (847) 559-7501 • Fax: (847) 291-4816 Email: os@omeda.com

PETROLEUM EVENTS Eldon Ball (Houston) eldonb@pennwell.com Niki Vrettos (London) nikiv@pennwell.com Frances Webb (London) francesw@pennwell.com Gail Killough (Houston) gailk@pennwell.com

EDITORIAL ADVISORY BOARD Luke R. Corbett, Anadarko David J. Greer, Shell International E&P Jack B. Moore, Cameron Corp. Hugh O’Donnell, Saipem Bruce Crager, J. Ray McDermott James K. Wicklund, Spinnerhawk Capital Management

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

Publications Mail Agreement Number 40052420 GST No. 126813153

Harnessing Thunder Horse

In this issue, Offshore brings you an exclusive report from BP on how the company met the many large scale challenges of developing its Thunder Horse deepwater field in the Gulf of Mexico. In December 2008, BP started production from the third and fourth wells at the Thunder Horse South field at more than 200,000 boe/d. The company plans to start-up additional production from wells in the Thunder Horse North field this year. BP operates Thunder Horse with 75% ownership. ExxonMobil has 25%. Every major feature of Thunder Horse – from discovery to production – has required BP and the industry to develop new capabilities, systems, and equipment, and required a combination of applied research and development, discipline, and focus, says Dan Replogle, Thunder Horse vice president. “The challenges of Thunder Horse brought out the best in our people and the best in the industry.” “Thunder Horse’s current production is a significant new source of US domestic energy, and is the second largest producing oil field in the US,” says Neil Shaw, BP senior vice president for Gulf or Mexico. “Thunder Horse has pushed the frontiers of deepwater technology that will be critical to our next phase of deepwater projects and to supplying America’s energy needs.” Sitting in 6,000 ft (1,829 m) of water about 150 mi (241 km) offshore, the Thunder Horse production-drilling-quarters (PDQ) semisubmersible is the largest production semi ever built, with a total displacement of 130,000 tons (117,934 metric tons). The topsides area of Thunder Horse is the size of about three football fields, and is packed with equipment and systems to treat and export 250,000 b/d of oil plus associated gas. “Thunder Horse has set new levels for deepwater exploration and production,” says Andy Inglis, BP’s chief executive of Exploration and Production. “With scores of new pieces of equipment or processes incorporated into the project, Thunder Horse has driven research and development efforts in many areas, including imaging and reservoir surveillance, drilling and completions equipment, and subsea and topsides production equipment.” Get the full report from BP, beginning on page 42.

Rig market adjusts to economy, oil price At the current oil price, the demand for all types of offshore rigs will remain flat. As new units are delivered into a flat market, fleet utilization will slide. Currently, worldwide offshore rig utilization stands at 87.6% as 647 of the world’s 739 jackups, semis, drillships, barges, tenders, submersibles, and arctic rigs are contracted. That’s the situation facing offshore drillers, as Justin Smith of ODS-Petrodata reports in this month’s issue. A total of 180 rigs currently are under construction and 86 do not yet have contracts, he points out. Some 54 of the 76 jackups under construction are without contracts, while only 12 of the 55 semis and 16 of the 43 drillships under construction are without contracts. An oil price of $50 to $60/bbl would ensure that most of the new rigs eventually would find work, he says, although day rates may come down to coincide with oil price. Read his full report, beginning on page 32.

Offshore Asia conference breaks new ground The 2009 Offshore Asia Conference & Exhibition will take place March 31-April 2, 2009, at the IMPACT Exhibition and Conference Center in Bangkok, Thailand. The Department of Mineral Fuels, Ministry of Energy, Thailand, has endorsed the conference, and PTT Exploration and Production Plc. (PTTEP) will be hosting. Dr. Kurujit Nakornthap, director-general of the Department of Mineral Fuels, and Anon Sirisaengtaksin, CEO of PTTEP, will address the conference at the ofﬁcial opening keynote session. “We are delighted Thailand will be hosting Offshore Asia 2009,” says Dr. Nakornthap. “The event will bring immense beneﬁts to the regional offshore oil and gas industry, and the country. Important subjects will be discussed during the three-day conference. We look forward to a successful and informative event.” Full details start on page 56.

To respond to articles in Offshore, or to offer articles for publication, contact the editor by email (eldonb@ pennwell.com) or fax (1-713-963-6296).

8 Offshore February 2009 • www.offshore-mag.com

0902off_8 8

2/11/09 2:07:02 PM

Build

better reservoir characterization.

Leverage the speed and

Better real-time data on formation gas improves your reservoir characterization,

accuracy of Weatherford’s

leading to more informed drilling, evaluation and completion decisions. Our GC-TRACER surface gas detector represents a major advancement in surface

GC-TRACER™ surface gas

logging technology. Using a patented, membrane-based extraction technology

detector to make more

coupled with a high-speed micro-gas chromatograph capable of extended

informed drilling, evaluation

hydrocarbon analysis (C10+), the GC-TRACER detector makes formation

and completion decisions.

gas analysis highly applicable, even in unconventional reservoirs. Extract and analyze gas samples in real time, and use accurate gas ratios at 15- to 60-second intervals to 𰁳𰂬 identify ﬂuid types, hydrocarbon maturity and degradation, sweet spots

in the pay, and occurrence of fractures and faults; 𰁳𰂬 improve ﬂuid sampling programs, pick casing points and geosteer

horizontal wells; 𰁳𰂬 provide an early indication of net pay, ﬂuid mobility, porosity and relative

formation permeability; 𰁳𰂬 enhance well planning, formation evaluation and completion design decisions.

For more information on our surface logging systems, contact an authorized Weatherford representative or visit weatherford.com.

Drilling

Evaluation

Completion Production

Intervention

0902off_9 9

2/11/09 2:07:05 PM

G L O B A L D ATA

Worldwide day rates

Active rig ﬂeet, January 2009

Year/Month

Floaters Jackups Far East 9 (+3) 21 (0)

North Sea 40 (+1) 34 (+1)

East Atlantic 2 (0) 0 (0)

US GoM

L. America

32 (0) 70 (-8)

SE Asia

47 (+2) 14 (0)

12 (-3) 48 (+1)

Mex GoM

M. East

5 (0) 31 (-2)

1 (0) 107 (+3)

W. Africa

S. Asia

31 (+1) 24 (+1)

10 (+1) 35 (+1)

Source: Rigzone.com

GoM drilling permits issued 100 90 80

70 60

Nov.

Dec.

40 30 20

10 0

June

July

Aug.

Sept.

Oct.

$520,000 $520,000 $520,000 $520,000 $520,000 $520,000 $520,000 $525,000 $525,000 $556,000 $556,000 $556,000

$19,300 $19,300 $19,300 $19,300 $19,300 $19,300 $19,300 $19,300 $19,300 $19,300 $19,300 $19,300

$131,558 $134,273 $133,839 $134,041 $135,041 $136,575 $137,426 $140,129 $141,608 $143,582 $145,055 $144,798

$320,000 $306,000 $306,000 $330,000 $330,000 $330,000 $330,000 $330,000 $330,000 $330,000 $330,000 $330,000

$53,750 $65,000 $65,000 $65,000 $80,000 $80,000 $80,000 $80,000 $80,000 $80,000 $80,000 $80,000

$271,511 $280,308 $283,955 $292,031 $298,607 $301,791 $307,157 $299,544 $304,872 $305,031 $313,864 $323,967

$478,000 $500,000 $525,000 $525,000 $525,000 $525,000 $525,000 $525,000 $525,000 $525,000 $580,000 $637,000

$272,579 $273,300 $273,248 $273,099 $277,800 $279,368 $292,031 $304,291 $316,768 $323,260 $327,818 $330,635

$43,000 $43,000 $43,000 $43,000 $43,000 $43,000 $43,000 $43,000 $43,000 $43,000 $43,000 $43,000

Maximum

Worldwide rig utilization

100

Average

Source: Rigzone.com

Source: US Minerals Management Service

Asia rig utilization

Minimum

Drillship 2008 Jan 2008 Feb 2008 March 2008 April 2008 May 2008 June 2008 July 2008 Aug 2008 Sept 2008 Oct 2008 Nov 2008 Dec Jackup 2008 Jan 2008 Feb 2008 March 2008 April 2008 May 2008 June 2008 July 2008 Aug 2008 Sept 2008 Oct 2008 Nov 2008 Dec Semi 2008 Jan 2008 Feb 2008 March 2008 April 2008 May 2008 June 2008 July 2008 Aug 2008 Sept 2008 Oct 2008 Nov 2008 Dec

Drillship Semisub Jackup

78 76

Dec. Jan. Feb. Mar. Apr. May Jun. July Aug. Sept. Oct. Nov. Dec. 2007 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008

Source: Rigzone.com

Month

Drillship Semisub Jackup Dec. Jan. Feb. Mar. Apr. May Jun. July Aug. Sept. Oct. Nov. Dec. 2007 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008 2008

Source: Rigzone.com

Month

10 Offshore February 2009 • www.offshore-mag.com

0902off_10 10

2/11/09 2:07:06 PM

Alcoa Oil & Gas high-strength, ultra-lightweight alloys can take you places you’ve never been before. We bring advanced aerospace technology down to earth in the search for oil and gas. Whether it’s one of our ultra-light drilling technologies, such as drill pipe or an engineered product forged to your speciﬁcation— Alcoa’s specialized manufacturing capabilities, experience, and patented alloys enable you to reach new frontiers. Drill Deeper, Farther, Faster Now drill deeper, farther and faster using your existing drilling assets. Offshore or on, Alcoa’s proprietary alloys and state-of-the-art designs give our drill pipe the strength of steel at half the weight. Today, you can achieve previously unattainable extended reach and deep drilling targets. Forging Ahead Alcoa’s global manufacturing capabilities provide customers with unparalleled resources. When you combine our patented metallurgical technology with our expertise in titanium, nickel or steel alloys, we can help you engineer products and manufacture components that will perform under conditions where low weight is critical and high strength is mandatory. From exploration and production, to reﬁning and transportation, let us take you places you’ve never been before.

www.alcoaoilandgas.com 888-379-1455

0902off_11 11

2/11/09 2:07:08 PM

GLOBAL E&P

Americas Pemex has contracted ICA Fluor to build two lightweight platforms for its Cantarell field in the Gulf of Mexico. The new structures, to be supplied and installed by ICA Fluor and its Mexican subsidiary, Industria del Hierro, will link to the existing Akal-R and Akal-L production platforms. ••• Offshore Trinidad, BHP Billiton has contracted J. Ray McDermott’s yard in Morgan City, Louisiana, for a platform for its Angostura gas export project. This will comprise a 4,000-ton (3,629-metric ton) topside; an 800-ton (726-metric ton), four-leg jacket; and 1,000 tons (907 metric tons) of piles. The work should be completed during spring 2010. Recently, J. Ray also supplied and installed a 9,100-ton (8,255-metric ton), four-leg jacket platform and 4,656 tons (4,224 metric tons) of piles for a platform for BG Trinidad & Tobago’s Poinsettia field in 530 ft (162 m) of water. The topsides were fabricated by the TOFCO joint venture in Trinidad, with Fluor providing overall project management. ••• Petrobras’ FPSO Cidade de Sao Mateus has left the Keppel Shipyard in Singapore and is undergoing installation on the Camarupim field off the coast of Espirito Santo. The vessel, chartered from Prosafe, will have an initial six-year tour of duty, with a potential six-year extension. It has been designed to handle 35,000 b/d of fluids and 353 MMcf/d of gas. Produced gas will be exported through pipelines, while oil will be stored in the hull for later transportation to shore by shuttle tankers. ••• BPZ Resources and Shell Exploration have terminated talks on a farmout agreement for blocks Z-1, XIX, and XXIII offshore Peru. BPZ will maintain its 100% interests in these and block XXII, which was not part of the discussions. The Houston-based company now will focus on a new oil development in block Z-1 centered on the Albacora and Corvina fields.

North Sea

of water in the West Cape Three Points license, penetrated 33 m (108 ft) of net pay from two intervals. Wireline logs and reservoir fluid samples suggest the well encountered stacked oil-bearing sandstones, confirming a significant extension of the Jubilee field to the southeast. The well also found oil in sandstones at Mahogany Deep, a target at a previously untested stratigraphic level below the oil/water contacts recorded during earlier exploration on Jubilee. Hyedua-2, drilled by the semi Blackford Dolphin, again to appraise Jubilee, flowed at rates of up to 16,750 b/d of oil, confirming good reservoir connectivity. It has been suspended for later use as a production well. Tullow says Phase 1 of the Jubilee development is on schedule to deliver first oil in the second half of 2010. ••• Total E&P Nigeria has started a two-year program of exploration and appraisal with a discovery on the shallow water Etisong prospect in OML 112. The Etisong-1 well, drilled in 70 m (230 ft) of water to a total depth of 2,207 m (7,241 ft), generated over 6,000 b/d of oil during tests from turbiditic reservoirs. Total aims to establish a new development pole in this license, taking in this discovery and other nearby structures.

Mediterranean Sea Noble has discovered gas in the deepwater Matan license offshore Israel. The well on the Tamar prospect, in 5,500 ft (1,676 m) of water, was drilled to TD of 16,076 ft (4,899 m) to test a subsalt lower Miocene target in the Levantine basin. Formation logs indicated net pay of more than 460 ft (140 m) in three reservoirs. Thickness and quality of the reservoirs exceed expectations, the company adds. Analysis to date suggests pre-drill gross mean resources of over 3 tcf of gas. Noble planned further production testing after completing the well, and may elect to keep the rig for two further wells in the basin. One could target a second subsalt, lower Miocene prospect.

StatoilHydro and its partners Marathon and GDF Suez expect to issue a development plan later this year for Gudrun field in the Norwegian sector. This will involve a fixed platform with seven wells and production tied back to existing facilities in the Sleipner area and the process plant at Kaarsto, north of Stavanger. Gudrun, in 110 m (361 ft) of water, 55 km (34.2 mi) north of Sleipner, contains oil and gas, with estimated recoverable volumes of 150 MMboe. The reservoir is complex, with high-pressure/high-temperature. It was first proven in 1974, with StatoilHydro becoming operator in 1997. There also are plans to connect a subsea system on the Sigrun field to the Gudrun platform at some point. ••• Offshore exploration activity on the UK continental shelf stayed high last year, according to Deloitte’s latest North West Europe Review. The report, compiled by Deloitte’s Petroleum Services Group, identified 121 exploration and appraisal well spuds in UK waters, only two down on the figure for 2007. Appraisal drilling accounted for 54% of that total, with 46% exploration-related. The Central North Sea remained the most active region, attracting 27% of wells in these categories. But there was a more even spread of wells than in recent years, with 67% directed at the Southern and Northern North Sea and the Moray Firth, off eastern Scotland. However, the sudden oil price slump and credit squeeze could transform the picture in 2009, Deloitte says. A downturn in new well activity late in 2008, is indicative of companies re-assessing their priorities.

Africa Tullow Oil has proven further oil from two appraisal wells in its deepwater Ghana permits. Mahogany-3, drilled in 1,236 m (4,055 ft)

Map shows Noble’s Tamar gas discovery offshore Israel.

12 Offshore February 2009 • www.offshore-mag.com

0902off_12 12

2/11/09 2:07:09 PM

0902off_13 13

2/11/09 2:07:13 PM

𰀿𰁤𰀖𰁪𰁞𰁛𰁩𰁛𰀖𰁭𰁗𰁪𰁛𰁨𰁩𰀻𰁎𰁆𰀻𰁈𰀿𰀻𰁄𰀹𰀻𰀖𰁟𰁩𰀖𰁡𰁛𰁯

Visit us at Subsea Tieback ‘09!

Booth #613

Project Management & Inspection End Measuring 𰁕 Material Traceability

0902off_14 14

GLOBAL E&P

Maersk Drilling has taken delivery of jackup, Maersk Resolve, its third of four newbuild jackups being built by Keppel FELS. The rig is designed to drill wells in up to 350 ft (107 m) of water to 30,000 ft (9,144 m) deep. The fourth rig in the series is scheduled for delivery in the second quarter of this year.

••• Mediterranean Oil & Gas (MOG) is seeking an offshore production concession from Italy’s government for the Ombrina Mare field in the Adriatic Sea. The application covers an offshore area of around 150 sq km (58 sq mi). Following successful appraisal drilling last year, MOG estimates the field’s 2P reserves at 20 MMbbl of oil and 6.5 bcf of gas. It plans to extract these via a single production platform with five wells, two of which will have dual completions for oil and gas. Produced oil would be sent to an FPSO with storage capacity for up to 50,000 metric tons (55,000 tons) of oil, while a 12-km (7.4-mi) submarine pipeline would be built to take the gas directly to an existing process plant onshore. MOG is targeting late 2011 for start-up, with production ramping up eventually to 7,500 b/d of oil and 3.5 MMcf/d of gas. ••• Offshore Libya, Hess has hit pay in the deepwater Arous Al-Bahar prospect. The A1-54/01 well, drilled to a depth of 11,077 ft (3,376 m) in 2,807 ft (856 m) of water, en-

countered a gross hydrocarbon section of around 500 ft (152 m) at various intervals.

Caspian Sea A joint venture of Aker Solutions, CB&I, and WorleyParsons has won a $135 million front-end engineering and design services contract for Phase II of the Kashagan full-ﬁeld oil development. The scope of work takes in both offshore and onshore facilities and pipelines, with options for early works, detail engineering, procurement services, technical assistance, and design/system integrity. It also provides for optional FEED programs for other ﬁelds in the Kazakh sector, including Aktote, Kairan, and Kalamkas. Work on the project started last November following a letter of intent from operator Agip KCO, and should be completed early next year. But additional options could extend the program up to an eight-year period. Kashagan has estimated oil reserves of 12-15 Bbbl.

Saudi Arabia Saudi Aramco has made a series of ﬁnds in the Arabian Gulf. Its Jurayd-101 well test-

2/11/09 2:07:14 PM

Creativity We found a way to cut well-completion costs in half. We found a better and faster method of inspecting clad pipelines. We’ve found solutions for complex problems on some of the most demanding projects on earth. And we keep ﬁnding new ideas all the time. Creativity is a part of everything we do – and everything we are. Three international R&D facilities. Forty full-time researchers. Nearly 300 active patents. All from one simple goal. Our clients demand the best – and that’s exactly what we give them.

We are ShawCor. Seven companies with one goal — to perform great feats for our clients.

www.shawcor.com

pipeline coatings

0902off_15 15

spoolable composite pipe

joint protection

weld inspection

tubular management

heat shrink

wire and cable

2/11/09 2:07:20 PM

GLOBAL E&P

ed oil from three reservoirs, flowing at combined rates of around 1,700 b/d of oil. The Arabiyah-1 well flowed 41.1 MMcf/d of gas during an open-hole test in the Khuff B reservoir, with a wellhead flow pressure of 5,865 psi on a 36/64-in. choke. Flow could be significantly higher under a normal production completion, the company added. Another Khuff B well, Hasbah-16, generated 62.1 MMcf/d of gas from an open-hole test at 12,700 ft (3,871 m), while over the Jauf reservoir, a cased-hole test on the Rabib-1 well at a depth of 17,130 ft (5,221 m) flowed at 40.6 MMcf/d.

India BP and Reliance Industries have been awarded deepwater block KG-DWN-2005/2, 40 km (25 mi) off India’s eastern coast, under the NELP VII licensing round. BP will operate with 30%, while Reliance holds the remaining 70% interest. The block covers an area of 1,949 sq km (752 sq mi). In the ﬁrst exploration phase, the partners will acquire 2D and 3D seismic and reprocess existing seismic data.

Asia/Paciﬁc CNOOC has budgeted $6.76 billion for its upstream projects this year, including $4.38 billion for development, $1.11 billion for ex-

0902off_16 16

ploration, and $1.12 billion for production. It expects to bring onstream 10 new projects, eight of them are offshore China, which also will be the focus of its exploration activity. In all, the company expects to drill over 80 wells and acquire over 30,000 km (18,641 mi) of 2D seismic, and 9,200 sq km (3,552 sq mi) of 3D seismic off China and elsewhere. ••• Production has started through two new fixed platforms in the Sakhalin II concession off Sakhalin Island. The PA-B installation is producing oil from the Piltun area of the Piltun-Astokhskoye field: the Astokh area has delivered oil since 1999 through the much smaller Molikpaq platform. In both cases, oil flows through the 800-km (497-mi) Trans-Sakhalin pipeline system to an export terminal in the south of the island. Shortly after PA-B came online, the LunA platform began producing gas from two wells on the Lunskoye field off northeast Sakhalin Island. The gas is sent through multiphase subsea pipelines to an onshore processing terminal. The treated gas then heads to the LNG plant on southern Sakhalin via the Trans-Sakhalin pipeline system. ••• Otto Energy has agreed to farm out 60% of its interest in Service Contract 55 in the Phil-

ippines to BHP Billiton Petroleum. The permit covers a deepwater block off southwest Palawan Island. In return, BHP will bear the full costs of a 3D seismic acquisition program and two exploratory wells, also assuming operatorship of the permit. The agreement is conditional on securing joint operating agreements and government approvals.

Australia Apache Corp. and Santos have agreed to supply gas from the offshore Reindeer field to CITIC Pacific’s Sino Iron project in Western Australia. Under a seven-year contract, the Reindeer partners will export 154 bcf of gas through a new 65-mi (105-km) subsea pipeline to a new process plant onshore at Devil Creek, capable of handling 210 MMcf/d. Exports should start during the second half of 2011. ••• Thailand’s PTTEP has signed a conditional shares agreement to acquire Australian company Coogee Resources for $170 million. Coogee has a 70.94% operated interest in the Jabiru and Challis oil field in the Timor Sea. The acquisition will also provide PTTEP with significant potential reserves from various Australian E&P licenses, including AC/L7, AC/RL7, AC/P32, AC/P34, and AC/P40. 

2/11/09 2:07:21 PM

Versabar 0902off_17 17

2/11/09 2:07:23 PM

OFFSHORE EUROPE

Norway buoyant, despite uncertainty High oil prices drove a surge in exploration and production activity across the Norwegian shelf last year. According to preliminary estimates from the Norwegian Petroleum Directorate (NPD), overall investments in the sector rose by more than NOK10 billion ($1.44 billion) in 2008 to over NOK130 billion ($18.77 billion). During this period, production increased by 4%, despite predictions of a steady decline. Much spending related to developments of large new fields such as Gjøa and Skarv, and continuing work on major production centers, including Ekofisk, Ormen Lange, Snorre, Troll Oil, and Valhall. The government approved plans for new projects on the Morvin and Yttergrytta fields in the Norwegian Sea, both tiebacks via subsea templates to the Aasgard complex. Yttergrytta came on stream last month.

Jeremy Beckman • London

proved disappointing. The well encountered two smaller gas columns in Mid-Triassic sandstone, but no further oil. As usual, StatoilHydro was one of the main beneficiaries in the latest Norwegian licensing round, the Awards of Predefined Areas (APA) 2008. The company gained interests in seven of the 34 production licenses offered, 21 located in the North Sea, 11 in the Norwegian Sea, and two in the Barents Sea. Nineteen companies gained operatorships, led by Wintershall, thanks to its recent acquisition of Norwegian independent Revus Energy. Among other awards, Sweden’s Lundin Petroleum will operate two licenses, including PL 501 in the North Sea, next to its promising Luno discovery. Another independent, Lotos, secured its first license as operator on the shelf. The awards carry obligations which should lead to nine firm wells being drilled – six in the North Sea, one in the Norwegian Sea (Wintershall), and one in the Barents Sea (DONG).

Independents face cash squeeze

Ormen Lange is one of the fields undergoing major incremental investment, according to the Norwegian Petroleum Directorate. Pictured is the subsea manifold for Norske Shell’s Phase 2 development undergoing mating with the third Ormen Lange subsea template at Grenland Group’s yard in Tonsberg. In May it will be offloaded to a barge for transportation to the field, 120 km (74.6 mi) northwest of Kristiansund. Picture: Tor Aas-Haug.

This year, a further 10 new projects could go forward, led by Gudrun in the North Sea and Goliat in the Barents Sea. Some, however, could be stalled if the oil price remains below $60/bbl. If that happens, NPD predicts, cost reductions – effected partly through suppliers lowering prices – will be needed to prevent a sharp drop in future activity. The NPD review also recorded 56 exploratory well spuds offshore Norway in 2008, up from 32 the previous year. Collectively, they yielded 25 discoveries, 12 in the North Sea, nine in the Norwegian Sea, and four in the Barents Sea. All those in the latter two regions were drilled by StatoilHydro. Among other operators, BG Norge found oil in Jurassic rock in the Cook formation in the northern North Sea, while Eni discovered gas east of Gullfaks. At year-end 12 new exploration wells were under way, and NPD forecasts 50 exploration well starts across the Norwegian sector this year, despite the increasingly depressed trading climate.

StatoilHydro starts year on a high StatoilHydro says it will operate or participate in 30-35 exploration wells around Norwegian waters this year. The company already has reported two discoveries. In the Norwegian Sea, a well and sidetrack drilled by the semisub Ocean Vanguard on the Dompap prospect, close to the Norne ﬁeld in 334 m (1,096 ft) of water, proved a 110-m (361-ft) oil column in the Aare formation. Recoverable reserves are estimated at 25-50 MMbbl. While Dompap should go forward for development, appraisal drilling on last year’s Obesum oil and gas ﬁnd in the Barents Sea

Around 160 companies active in the North Sea are inherently unstable, with over half of them having little or no production or cash flow. So claimed Chris Bulley of analysts Hannon Westwood at the recent Prospex conference in London, predicting a “long overdue rationalization amongst the smaller players.” Oilexco looked to be the first casualty last month, calling in administrators from Ernst & Young following its failure to secure sufficient funding. The Calgary-based company had blazed a trail for independents in the UK Central North Sea in recent years, taking rigs on longterm contracts to drill and to develop a series of discoveries. It also generated cash from tiebacks of its Brenda and Nicol finds to the Balmoral floating platform – not enough, however, to cover its forward commitments. These included the Huntington development in license P.1114, where the remaining partners acted swiftly to install Germany’s E.ON Ruhrgas as the new operator. As for Balmoral, where Oilexco is duty holder, operations were continuing as normal in January. Another floater, the Sevan Voyageur, had sailed out to Oilexco’s Shelley field and is undergoing final commissioning, despite uncertainties over the project’s future. Other financially straitened companies have managed to soldier on. Ithaca Energy managed to keep its Jacky project in the Moray Firth alive via a cash injection from Dyas. The Jacky platform and pipelines were installed last month, following serious weather delays, and the field should be onstream mid-March. Oil at an initial rate of 7,500 b/d will be exported to the Beatrice facilities, which Ithaca acquired from Talisman Energy. Another leading UK independent, Venture Production, has brought the Grouse oil field on stream in block 21/19 through a single subsea production well tied back to the Kittiwake platform. Grouse is connected through a tie-in to a pipeline bundle installed during development of the Goosander satellite in 2006. Venture is thought to be in good shape, with much of its North Sea production coming from gas which is less sensitive to price fluctuations. However, the company was reportedly on the radar recently of UK utility Centrica.

Marathon quits Kinsale Petronas subsidiary Star Energy has agreed to buy Marathon’s production interests in southern Ireland for $180 million. The main asset is the Kinsale Head complex, which produces gas from the Kinsale Head, South West Kinsale, and Ballycotton ﬁelds in the Celtic Sea. Star will also gain an 86.5% interest in the Seven Heads ﬁeld, formerly developed by Ramco, which is tied back to the Kinsale facilities, along with Marathon’s gas storage business which has current capacity of 7 bcf. Current net production through the complex is 36 MMcf/d. Star will retain Marathon’s 61 employees in Ireland; the deal does not include Marathon’s 18.5% interest in Shell’s Corrib development offshore western Ireland. 

18 Offshore February 2009 • www.offshore-mag.com

0902off_18 18

2/11/09 2:07:24 PM

One Company. One Call.

Bring us your biggest challenges. Take home the right solutions. Booth 301, Subsea Tieback Forum & Exhibition, San Antonio, Texas March 3-5, 2009

0902off_19 19

2/11/09 2:07:27 PM

David Paganie • Houston

GULF OF MEXICO

Final call for central lease sale MMS has issued the final notice for a Federal oil and gas lease sale in the Central Gulf of Mexico. Proposed Lease Sale 208, scheduled for March 18 in New Orleans, includes 6,459 unleased blocks covering more than 34.6 million acres offshore Louisiana, Mississippi, and Alabama. Also included is 4.2 million acres in the southeastern part of the CGOM Planning Area, known as 181 South Area, which has not been offered for lease since 1988. “The addition of 181 South Area is significant because the states of Alabama, Mississippi, Louisiana, and Texas will share in all revenue from leases in this new area,” says Randall Luthi, director of MMS. The Gulf of Mexico Energy Security Act of 2006 mandated that 181 South Area be offered for lease, and that the four Gulf producing states share in those revenues. MMS has increased the rental rates for leases offered in this sale, from $6.25/acre to $7.00/acre in water depths of less than 656 ft (200 m) and from $9.50 to $11.00/acre in 656 ft or deeper. For the first time, rental rates will be raised for all leases with initial terms of more than five years and for leases with an approved extension of the initial lease period. MMS estimates that this sale could gener-

ate 0.807 to 1.336 Bbbl of oil and 3.365-5.405 tcf of natural gas. The acreage is from 3 to 230 mi (5 to 370 km) offshore in water depths of 10 ft (3 m) to more than 11,200 ft (3,400 m). Meanwhile, MMS has initiated a 60-day comment period on its Draft Proposed 2010-2015 OCS Oil and Gas Leasing Program (DPP). The regulatory agency also has submitted a notice of its intent to prepare an Environmental Impact Statement for the DPP. “We’re basically giving the new Administration a two-year head start,” Luthi says. “This is a multi-step, multi-year process with a full environmental review and several opportunities for input from the states, other government agencies and interested parties, and the general public.” MMS estimates the OCS contains about 86 Bbbl of oil and 420 tcf of natural gas in undiscovered ﬁelds.

TGS completes GoM surveys Ahead of the lease sale in March, TGS-NOPEC Geophysical Co. (TGS) has completed multi-client higher order depth imaging projects that will be used to evaluate hydrocarbon potential in the areas available for lease. TGS says it has created the industry’s ﬁrst multi-client reverse time migration (RTM) product on the Stanley 3D survey. The migration covers an 8,900-sq km (3,436-sq mi) deepwater area in Green Canyon and Walker Ridge. Final survey results have been delivered to the early participating customers. In addition, TGS has completed an anisotropic Kirchhoff depth migration on its Eastern Mississippi Canyon, Deep Resolve, and Sophie’s Link 3D surveys. Anisotropic migration uses well data to calibrate the seismic to the true earth, which provides better positioning and more accurate imaging of the subsurface, the company explains. These new imaging products tie to the existing anisotropic migration previously completed in the Mississippi Canyon area. TGS now offers 32,000 sq km (1,236 sq mi) of contiguous and seamless anisotropic depth migration in the central GoM. The projects incorporated over 800 well logs in building the anisotropic model.

InterMoor gets exclusive rights to torpedo piles InterMoor is now the exclusive licensee of torpedo pile technology in the US. The rights were granted to InterMoor by Petrobras on Nov. 28, 2008. In the last eight years, Petrobras has installed more than 1,000 torpedo piles, says InterMoor. The piles are essentially gravity-embedded cylindrically-shaped projectiles used to anchor deepwater ﬂowlines and facilities, the company explains. Torpedo piles typically range in size from 24 to 98 metric tons (26 to 108 tons). The largest torpedo pile can provide anchor-holding capacity of up to 1,000 metric tons (1,102 tons).

“Petrobras’ extensive experience in the use of torpedo piles has shown them to be both economical and less time consuming to install than alternatives, such as suction piles or drag-embedded plate anchors,” says Bob Wilde, InterMoor chief engineer. “InterMoor looks forward to extending this technology to the Gulf of Mexico and other US waters.” Petrobras noted in its DOCD ﬁled with the MMS for the Cascade-Chinook development that it was considering torpedo piles to moor the planned FPSO for Phase 1. The base-case scenario included suction piles.

Chouest expands shipyard capacity Edison Chouest has expanded its shipbuilding capacity on the Gulf Coast with the assignment of Tampa Bay Shipbuilding and Repair’s long-term lease agreement with the Tampa Bay port. Chouest has named the new acquisition Tampa Ship LLC. The company subsequently has assumed management and operation of the yard previously owned by a group associated with Bender Shipbuilding and Repair. “Tampa Ship provides us more capacity for new construction and the repair of much larger vessels,” says Gary Chouest, president of Edison Chouest. “Now that we have closed on the purchase, we are looking forward to construction on our ﬁrst new vessel this month (January).”

The Tampa shipyard has capacity for conversion, overhaul, and repair work. The 60-acre facility has two transporters, a 600-ft (183-m) assembly building, lifting units, crawler cranes, and four graving docks capable of servicing ships up to 15,000 dwt. The company also intends to use the yard for commercial repair and dry-dock services in support of the maritime industry. Meanwhile, Chouest has agreed to assist in the phase out of a new construction deal with Bender. The previous owner had been building three barges for Overseas Shipholding Group. Chouest will assist in completing that deal, slated for a late 2009 delivery. Tampa Ship is accessible from the GoM via a 43-ft (13-m) deep channel. The yard fronts Sparkman Channel, which is 34 ft (10 m) deep and 700 ft (213 m) wide. Planned improvements include dredging a 30-ft (9-m) deep slip. 

20 Offshore February 2009 • www.offshore-mag.com

0902off_20 20

2/11/09 2:07:28 PM

SPERRY DRILLING SERVICES

InSite into your reservoir.™

On target for optimal recovery. In complex geology, the InSite ADR™ Azimuthal Deep Resistivity sensor helped achieve optimal well placement. Customer Challenge: Faced with drilling shallow

wells in an area of high geological and operational complexity, a Latin American operator needed to improve well positioning and maximize recovery. Halliburton’s Solution: A combination of Sperry’s

InSite ADR™ Azimuthal Deep Resistivity sensor and StrataSteer® 3D geosteering service for optimized wellbore placement enabled the operator to make immediate geosteering decisions and position wells in the reservoir’s most productive zones. Results: The operator was able to steer the well path

into the best possible target—thereby reducing geological uncertainties, optimizing drilling operations and delivering one of the highest percentages of net pay per lateral length for wells drilled in the past six months.

Get more InSite into your reservoir.™ www.halliburton.com/adr. ®

InSite generation: Deeper reading Higher resolution Faster telemetry Greater reliability

HALLIBURTON

0902off_21 21

2/11/09 2:07:34 PM

Gene Kliewer • Houston

SUBSEA SYSTEMS

US continental shelf BP has ordered $100-million in subsea production systems from Cameron for tieback projects in the Gulf of Mexico. The scope includes four subsea trees, production control systems, manifold, flowline connections, engineering and project management, plus related equipment. Delivery is scheduled to start in 4Q 2009 and continue through 2010. “This is the first in a series of orders to be placed under our 2006 Gulf of Mexico frame agreement with BP, and reflects the result of a joint standardization and engineering effort with BP over the past two years,” says Jack B. Moore, Cameron president and CEO. NACE International has opened a $2.4-million training center for corrosion education in Houston. The 15,000-sq ft (1,394-sq m) facility has a cathodic production test field with buried, electrified pipelines, coatings lab with blast and spray booth, virtual spray booth, classroom training, equipment preparation area, and marine ballast tank immersion test. Noble Energy has signed a five-year frame agreement with FMC Technologies as its preferred subsea equipment supplier for deepwater GoM projects. FMC will supply subsea production systems including enhanced horizontal subsea trees, related installation services, controls, manifolds and tie-in systems. FMC Technologies has acquired a 45% interest in Schilling Robotics for $116 million. “Our global subsea franchise will assist Schilling Robotics in extending its reach worldwide and better position it to serve its customers,” says Peter D. Kinnear, FMC Technologies chairman, president, and CEO. “Additionally, the relationship will allow FMC to participate more fully in the increasing integration of remote activities performed on the seabed such as subsea processing, well intervention, and production optimization.” FMC Technologies is also acquiring the rights to exercise an op-

60th pipeline bundle Subsea 7 Inc. successfully launched and installed its 60th pipeline bundle. The milestone was a 1.3-km (0.8-mi) long bundle for BP’s Machar field in the North Sea. The $22-million contract covers a 12-in. (30.5-cm) sleeve containing a dry insulated 8-in. (20-cm) lined production pipeline, 6-in. (15-cm) plastic lined water injection flowline, 3-in. (7.6-cm) gas lift line, plus electrical power and signal cables and hydraulic and chemical controls tubing. The bundle was launched from Wick, Scotland and transported to location using controlled depth towing.

tion over the two-year period beginning in 2012 to acquire the remaining 55% of the company.

North Sea BP has renewed a contract with Aker Solutions for life-of-field subsea engineering services covering West of Shetland assets. The threeyear contract includes options for two one-year extensions. The total value over five years could reach £25 million ($36.6 million). Aker will provide project management for subsea field developments from its Aberdeen, UK, office. A manifold with utility gear was lifted and mated with the third Ormen Lange subsea template early in January at the Grenland Group’s Tønsberg, Norway, facility. The 44-m by 33-m by 15-m (144-ft by 108-ft by 49-ft) subsea station is scheduled for offloading and transportation to Ormen Lange in May where it will be installed in 900 m (2,953 ft) of water.

Asia/Paciﬁc

Jacky, Beatrice set for production The Jacky field platform and production pipelines plus connection to the existing Beatrice field platform are installed and production is scheduled onstream in mid-March in the Inner Moray Firth of the UK. Weather had delayed the Jacky installation, but Ithaca Energy Inc. was able to secure the Hermod heavy-lift vessel which had been undergoing maintenance at Rotterdam. The j ackup Ensco 92 is scheduled into the field late this month for well work, and tie-in work is set for Beatrice. Once all work is complete, initial flow is expected to be 7,500 b/d of oil. Jacky is owned by Ithaca (67.3% as operator), Dyas (22.7%), and North Sea Energy (10%) and is being developed as an unmanned facility with a single well tied back to the Beatrice facilities.

ExxonMobil Exploration and Production Malaysia Inc. has contracted J. Ray McDermott afﬁliate Barmada McDermott Sdn. Bhd. in Malaysia for transportation and installation of a 1.5-mi (2.4-km) long, 12-in. (30.5-cm) replacement pipeline between Guntong-C and Guntong-A. The existing Guntong-C riser and a section of the existing pipeline will be replaced with tie-in to the existing pipeline. A mechanical connector will connect the new pipeline to the remaining section of the existing pipeline. Front-end engineering and design for development of the Beibu Gulf block 22/12 offshore China is under way by Roc Oil. The proposed development calls for the construction and installation of a wellhead platform at Wei 6-12S in the northern part of the permit and a tie-back to the central processing platform at CNOOC’s Weizhou 12-1 discovery, about 1,800 m (5,905 ft) away from block 22/12. Unmanned minimal structures at Wei 12-8W and Wei 12-8E in the southern part of the permit will be installed and progressively tied back to Wei 12-1 platform. First oil is scheduled in early 2011. Roc Oil holds 40% in the permit. Partners are Horizon Oil Ltd. with 30%, Petsec Petroleum Inc. with 25%, and Oil Australia Pty Ltd. with 5%. 

22 Offshore February 2009 • www.offshore-mag.com

0902off_22 22

2/11/09 2:07:35 PM

0902off_23 23

2/11/09 2:07:39 PM

VESSELS, RIGS & SURFACE SYSTEMS

2009 predicted to be a tough year for offshore rigs The latest headlines from many newspapers and magazines paint a grim picture for 2009 – “slumping economy, credit crunch, recession, plunging oil prices.” The current state of the economy is predicted to result ultimately in fewer offshore rigs on the market in 2009, a drop in utilization, and eventually a drop in day rates. While some new rigs continue to be built, some contractors are having a hard time finding financing, resulting in canceled orders. Commonplace in today’s economy is for existing rigs to be stacked once a contract is up, as owners wait for better economic times. Established companies with cash resources seem to be fairing better, and continue moving forward. Many factors go into determining which of the categories a company fits.

Pride International’s jackup Pride Mississippi, one of the company’s idle US-based rigs as of January.

Brian Uhlmer, research analysis with Pritchard Capital Partners LLC, says companies that have cash flow and are viewed as solid continue to be able to obtain credit. “However, for the speculative guys, even with contracted rigs, we have seen credit cut off.” Like Scorpion Offshore, which was unable to secure financing for its Deepwater Rig a semisubmersible Keppel FELS in Singapore was to build. Scorpion already had invested about $74 million into it, according to Uhlmer. Despite the fact that Scorpion has operational experience and has jackups currently in operation to create some cash flow, and despite the fact that the semisub was contracted with Petrobras and being built at a well-known yard, it did not find financing. Seadrill announced in January that it has amended its agreements with PPL Shipyard and Keppel FELS for the construction of four new jackups — postponing payments. Seadrill has issued corporate guarantees for the remaining installments on the first two units. However, no guarantees were made for payments on the second units at the yards. “But they also are trying to buy Scorpion which has seven jackups -- so they had to make a decision and they realized it would be cheaper to average in and buy all of Scorpion,” Uhlmer said (prior to the official announcement from Seadrill).

Rig utilization Uhlmer says there has not been a drop in working rigs — not yet anyway. “But there have been a couple of floaters come off without follow-on contracts.” For example, the second generation semisubmersible Atwood Southern Cross now is sitting idle, which, according to Uhlmer, “no one thought that would be a problem back in June.” Another example is Diamond Offshore’s Ocean Victory fourth generation semisubmersible. It still awaits contract resolution with Callon Petroleum and is on standby until March. The two-well, sixmonth contract was to drill and complete Callon’s Entrada field wells in the Gulf of Mexico beginning in October 2008. In November, Callon announced it had decided to suspend operations to develop Entrada field due to “significantly higher than expected costs incurred to date and commodity prices which have declined to less than half of their levels when development operations began in mid-2008.” Callon said it does not anticipate returning to the project. The good news for Diamond is that Ocean Victory is contracted to start work for ATP in March for a minimum of one year. “Utilization drop and idle time is a precursor to day rate drops -- not the other way around,” Uhlmer says. “Rigs have to sit idle for a while and there have to be a lot of rigs idle before people start to get desperate.” Worldwide offshore rig fleet utilization was at 87.7% in early January, according to ODS Petrodata, down only slightly year-over-year. Hercules Offshore, the drilling rig contractor with the most exposure to the weakening shallow water market in the GoM, has cold stacked a number of its regional jackups, submersibles, and inland barges until demand improves. The company has only four rigs contracted to work in the GoM post 1Q 2009. In Pride International’s latest monthly fleet update, the company announced its jackup Pride Nevada, whose contract ended in December, has been stacked. Pride Mississippi was stacked after its contract was up in October. And earlier in the year, Pride Alabama and Pride Colorado took the same path as Pride Utah did in 2007. The latest to stack a rig is Transocean. In its January fleet status report, the Transocean Nordic is listed as stacked. According to Pritchard, the jackup was to be sold to a Kuwaiti company for $170 million. “In December 2008, the sale agreement was terminated,” says Transocean’s report. This is the second sale that has been terminated in recent months, Pritchard says. Transocean also terminated a contract with Burgundy Global Exploration Corp. when Burgundy failed to post the required escrow. The second half of 2009 could prove challenging, as more contracts are scheduled to expire for several major drilling contractors.

Day rates For 2009, Uhlmer predicts a 10-15% reduction in rates for premium jackups. For commodity style jackups, 250s and below, he thinks there will be a 30-40% decline, as well as signiﬁcant idle time. With the way jackups are rolling over, it probably will be around March before a reduction is seen, he adds. GoM commodity jackups have been affected the most, as rates have already dropped from $70,000 to $50,000, Uhlmer says. This is followed by the international commodity jackups. And ﬂoaters are predicted to head the same direction. “The midwaters are probably going to be hit with some idle time and 30-40% reduction [in rates].” For ultra deepwater, Uhlmer says he is modeling new contract day rates around $550,000. The peak price in 2008 was $650,000. “There’s also not a lot available in the ultra deepwater, so I don’t even know if we will see contract announcements.” The last deepwater rate Uhlmer saw was $585,000 which is about a 10% drop from the $650,000 high. Uhlmer says he has not seen any new contracts on midwaters. “Midwater has some marginal prospects; if you are going to drill some of those prospects you need commodity prices to support it and also you

24 Offshore February 2009 • www.offshore-mag.com

0902off_24 24

2/11/09 2:07:40 PM

𰁊𰁥𰁝𰁛𰁪𰁞𰁛𰁨𰀢𰀖𰁭𰁛𰀖𰁙𰁗𰁤𰀖𰁙𰁚𰁡𰁞𰁫𰁚𰁧𰀕𰁪𰁣𰁙𰁚𰁧𰀕𰁖𰁣𰁮𰀕𰁠𰁞𰁣𰁙𰀕𰀕𰁤𰁛𰀕𰁥𰁧𰁚𰁨𰁨𰁪𰁧𰁚𰀕𰃅𰀕𰁞𰁣𰁘𰁡𰁪𰁙𰁞𰁣𰁜𰀕𰀦𰀣𰀨𰀫𰀥𰀕𰁗𰁖𰁧𰀡𰀕𰀧𰀕𰁠𰁞𰁡𰁤𰁢𰁚𰁩𰁧𰁚𰁨𰀕𰀕𰁪𰁣𰁙𰁚𰁧𰀕𰁩𰁝𰁚𰀕𰁨𰁚𰁖𰀣𰀾𰁩𰃉𰁨𰀕𰁩𰁞𰁢𰁚𰀕𰁩𰁤𰀕𰁨𰁝𰁤𰁬𰀕𰁩𰁝𰁚𰀕𰁬𰁤𰁧𰁡𰁙𰀕𰁤𰁪𰁧𰀕𰁜𰁡𰁤𰁗𰁖𰁡𰀕𰁚𰁣𰁚𰁧𰁜𰁮𰀕𰁨𰁪𰁥𰁥𰁡𰁮𰀕𰁞𰁨𰀕𰁙𰁚𰁚𰁥𰁚𰁧𰀕𰁩𰁝𰁖𰁣𰀕𰁤𰁣𰁚𰀕𰁢𰁞𰁜𰁝𰁩𰀕𰁩𰁝𰁞𰁣𰁠𰀣𰀕𰁅𰁖𰁧𰁠𰁚𰁧𰀕𰀕𰁞𰁨𰀕𰁝𰁚𰁡𰁥𰁞𰁣𰁜𰀕𰁩𰁤𰀕𰁗𰁧𰁞𰁣𰁜𰀕𰁞𰁩𰀕𰁩𰁤𰀕𰁩𰁝𰁚𰀕𰁨𰁪𰁧𰁛𰁖𰁘𰁚𰀕𰁨𰁖𰁛𰁚𰁧𰀕𰁖𰁣𰁙𰀕𰁛𰁖𰁨𰁩𰁚𰁧𰀣𰀕𰁌𰁚𰀕𰁤𰁛𰁛𰁚𰁧𰀕𰁖𰀕𰁛𰁪𰁡𰁡𰀕𰁧𰁖𰁣𰁜𰁚𰀕𰁤𰁛𰀕𰁣𰁛𰁚𰁟𰁫𰁣𰀣𰀖𰁗𰁤𰁚𰀖𰀖𰁞𰁟𰁝𰁞𰀣𰁦𰁨𰁛𰁩𰁩𰁫𰁨𰁛𰀖𰁥𰁟𰁢𰀖𰁗𰁤𰁚𰀖𰁝𰁗𰁩𰀖𰁙𰁥𰁤𰁬𰁛𰁯𰁗𰁤𰁙𰁛𰀕𰁖𰁣𰁙𰀕𰁟𰁤𰁩𰁪𰁨𰁫𰁣𰁛𰁤𰁪𰁗𰁪𰁟𰁥𰁤𰀖𰁩𰁥𰁢𰁫𰁪𰁟𰁥𰁤𰁩𰃆𰀕𰁖𰁡𰁡𰀕𰁙𰁚𰁨𰁞𰁜𰁣𰁚𰁙𰀕𰁬𰁞𰁩𰁝𰀕𰁩𰁝𰁚𰀕𰀕𰁗𰁚𰁨𰁩𰀕𰁖𰁫𰁖𰁞𰁡𰁖𰁗𰁡𰁚𰀡𰀕𰁨𰁖𰁛𰁚𰁨𰁩𰀕𰁩𰁚𰁘𰁝𰁣𰁤𰁡𰁤𰁜𰁞𰁚𰁨𰀣𰀕𰀻𰁧𰁤𰁢𰀕𰀨𰀥𰀠𰀕𰁠𰁞𰁡𰁤𰁢𰁚𰁩𰁧𰁚𰁨𰀕𰁡𰁤𰁣𰁜𰀕𰁦𰁥𰁭𰁛𰁨𰀖𰁗𰁤𰁚𰀖𰁦𰁨𰁥𰁚𰁫𰁙𰁪𰁟𰁥𰁤𰀖𰁫𰁣𰁘𰁟𰁢𰁟𰁙𰁗𰁢𰁩𰀕𰀕𰁩𰁤𰀕𰁩𰁝𰁚𰀕𰁭𰁥𰁨𰁢𰁚𰃊𰁩𰀖𰁣𰁥𰁩𰁪𰀖𰁗𰁚𰁬𰁗𰁤𰁙𰁛𰁚𰀖𰁩𰁛𰁗𰁢𰁟𰁤𰁝𰀖𰁪𰁛𰁙𰁞𰁤𰁥𰁢𰁥𰁝𰁯𰀕𰁗𰁪𰁞𰁡𰁩𰀕𰁩𰁤𰀕𰁬𰁞𰁩𰁝𰁨𰁩𰁖𰁣𰁙𰀕𰁙𰁚𰁢𰁖𰁣𰁙𰁞𰁣𰁜𰀕𰁝𰁞𰁜𰁝𰀢𰁩𰁚𰁢𰁥𰁚𰁧𰁖𰁩𰁪𰁧𰁚𰀡𰀕𰁝𰁞𰁜𰁝𰀢𰁥𰁧𰁚𰁨𰁨𰁪𰁧𰁚𰀕𰁖𰁥𰁥𰁡𰁞𰁘𰁖𰁩𰁞𰁤𰁣𰁨𰀡𰀕𰁅𰁖𰁧𰁠𰁚𰁧𰀕𰁬𰁞𰁡𰁡𰀕𰁝𰁚𰁡𰁥𰀕𰁮𰁤𰁪𰀕𰁞𰁣𰁘𰁧𰁚𰁖𰁨𰁚𰀕𰁚𰁛𰃑𰁘𰁞𰁚𰁣𰁘𰁮𰀕𰁖𰁣𰁙𰀕𰁙𰁚𰁘𰁧𰁚𰁖𰁨𰁚𰀕𰁧𰁞𰁨𰁠𰁨𰀣𰀕𰁋𰁞𰁨𰁞𰁩𰀕𰁥𰁖𰁧𰁠𰁚𰁧𰀣𰁘𰁤𰁢𰀣𰀕𰀶𰁣𰁙𰀕𰁨𰁚𰁚𰀕𰁬𰁝𰁮𰀕𰁣𰁤𰁗𰁤𰁙𰁮𰀕𰁗𰁚𰁖𰁩𰁨𰀕𰁅𰁖𰁧𰁠𰁚𰁧𰀕𰁛𰁤𰁧𰀕𰁗𰁧𰁚𰁖𰁙𰁩𰁝𰃅𰁖𰁣𰁙𰀕𰁛𰁤𰁧𰀕𰁙𰁚𰁥𰁩𰁝𰀣

𰁬𰁬𰁬𰀣𰁥𰁖𰁧𰁠𰁚𰁧𰀣𰁘𰁤𰁢𰀕𰀕𰀠𰀩𰀩𰀕𰀦𰀩𰀩𰀧𰀕𰀨𰀪𰀭𰀩𰀧𰀮𰁚𰁥𰁞𰁘𰀵𰁥𰁖𰁧𰁠𰁚𰁧𰀣𰁘𰁤𰁢

0902off_25 25

2/11/09 2:07:43 PM

VESSELS, RIGS & SURFACE SYSTEMS

need the lenders to help pay for that drilling program. If you are a smaller producer, and it is not within your cash ﬂow to drill, you have to borrow the money to drill. So if they won’t lend you any money – you are not drilling.” The average worldwide day rate for jackups rated to work in water depths greater than 300 ft (91 m) has fallen about 6% since September 2008, according to ODS Petrodata, although rates for rigs rated for lesser water depths so far have remained relatively stable.

When will it rebound? “I do not think premium jackups are going to fall off that much. I cannot see the commodity jackups rebounding in 2009 at all after they fall off. That will have to be sometime in 2010. So many of these jackups, rigs in general, but even jackups, are getting more than two-year terms now, so you do not have a lot of rollovers, so that is why rates are not getting cut in half or 80%. There is a good supply, it is not going to be the en-

Safeguard the environment while protecting your investment...

tire ﬂeet rolling over.” Demand is deﬁnitely waning. Uhlmer has been tracking rig tenders. “There are a lot of possible tenders that were supposed to close in December and none of them picked up rigs.” Companies are waiting for things to get better, putting projects on the back burner. “They know if I do not need to drill quickly to get this gas to market while commodity prices are down, why not wait it out and see if I can squeeze rates in. $50,000/day is a lot of money, especially when these rigs are going for $150,000 for commodity jackups, at $140,000-$150,000 where the out cost is only $40,000. With depreciation and other costs, that rig can work and make a pretty good margin at $70,000-80,000, so why not wait. Once you have a few of them idle you’ll say maybe I did need to chop my rates. If you just have one idle, there’s no reason, lay off your crew, sit the rig there for six months, and wait.”

Who is surviving the crunch?

Specify DRESSER ABS-Approved Couplings! Dresser Piping Specialties has been granted the American Bureau of Shipping type approval for ¿re rated couplings that meet and exceed the previous 2007 and 2008 ABS rule changes. Typical applications for the ABS approved Dresser® coupling include above deck inert gas lines, cargo oil lines, bilge systems, fuel oil transfers, and lube oil transfer systems. Each authentic Dresser coupling can be quali¿ed to working pressures up to 19.2bar (275psi). Fire testing was successfully conducted per ABS Rules to meet the demanding standards of ISO 19921 and 19922.

0902off_26 26

Dresser couplings are widely used on marine piping systems for their ability to absorb vibration, expansion and contraction while providing trouble-free, lifetime leakproof dependability. For further information please contact your nearest Dresser Representative, or call Dresser Export Sales at 814-362-9200. Visit us at www.dresser.com

Piping Specialties, Dresser, Inc. Bradford, PA 16701 USA Phone: (814) 362-9200 Email: marinesales@dresser.com

“Noble is really in good shape, it has a high percentage of its jackup days contracted in 2009,” Uhlmer says, adding that Noble only has one floating rig coming available in July, but it is one of the only rigs available so there should not have any trouble getting a contract. With almost no net debt, Noble has the ability to go after any opportunities that arise in the future, he says. And Transocean has “so much free cash flow coming in this year on contracts with all of the NOCs and IOCs, and not a lot of exposure to lower-end operators who could have financial problems and go bankrupt.” Ulhmer says the companies that have not over-leveraged themselves, have free cash flow, and have been able to pay down their debt will be OK. Stability outweighs cost in many instances. “You have kind of a shift, people doing these projects are saying ‘I need a company who’s going to be here six months from now, a year from now, two years from now,’ so just being established helps as well.” Uhlmer says the current credit crunch is unlike those of the past. “The difference in this cycle that people haven’t realized is that in the ’80s right before the major downturn there was a huge build cycle with almost 300 rigs built. Then the down cycle came in commodities, not the overall economy and the huge credit crunch. So all these rigs were allowed to be built and then got stacked. This time around, the rigs have stopped being built. So rigs should probably not get affected as much as you would have expected in the past cycles.” 

2/11/09 2:07:44 PM

Pumping Systems - to the world oil & gas industry... In the international oil and gas industry Frank Mohn Oil & Gas are recognised as a leading designer, manufacturer and supplier of complete pumping systems for both onshore and offshore applications. Keywords are solid craftmanship combined with innovation and world-wide service. One System, one supplier, time saving and cost effective.

“P-52”

Courtesy of PETROBRAS

- Firewater Pumps - Seawater Lift Pumps - Water Injection Pumps - Crude Offloading Pumps

Frank Mohn Flatøy AS

N-5918 Frekhaug - Norway tel. +47 55 999 400 - fax +47 55 999 581 oilandgas@framo.com www.framo.com

0902off_27 27

Please visit us at our stand in Commercial Norwegian Pavilion Zhenwei International Petroleum exhibition Stand E3239

2/11/09 2:07:47 PM

DRILLING & PRODUCTION

VAALCO drilling off to strong start in Gabon VAALCO Energy has drilled one pilot hole south of the original Ebouri discovery and a second pilot hole northeast of the original discovery offshore Gabon. The holes delineated additional Gamba sandstone reservoir above the oil/water contact, thereby increasing the acreage and reserves of the Ebouri field. VAALCO is completing the development well horizontally on the same orientation as the second pilot hole. First oil production from the well was expected (at presstime), the company says. The company also hit with the North Ebouri appraisal well in the Etame block northeast of the Ebouri platform. The well struck a 21-ft (6.4-m) oil column, further expanding Ebouri field. VAALCO plans a sidetrack to optimize the location for a possible second horizontal development well. In addition, the company plans two exploration wells (North Etame and South East Etame) on newly mapped structures. The wells will be drilled back-to-back using Pride Cabinda. VAALCO expects to bring total production from the Etame license to approximately 25,000 b/d of oil. The Etame license areas currently produce approximately 20,000 b/d, of which VAALCO has a 28.1% working interest. The piling operations were performed on schedule and without incident exactly as planned, despite the soil variety. The $2-million drilling and grouting contract was the first ever for newly formed Large Diameter Drilling (LDD) Ltd. Since the project is based on a floating construction vessel, heave forces were the main concern. The motion of the vessel could damage the well or the equipment, causing project delays. Given the mere 1.5-in. (3.8-cm) radial tolerance from the bit through the center of the 42-in. (107-cm) tubular pile, LDD opted to use a passive heave compensator to keep the drill from snagging on withdrawal or from touching the base of the pile. The heave compensator, with a 3-m (10-ft) stroke for safe working loads up to 60 tons (54 metric tons), was able to reduce point loading to just under a ton (907 kg). “As far as we are aware, no one else has ever used a lift compensator such as this for a drilling and piling operation,” says Andy Seager, operations manager at LDD. Soil conditions posed an unexpected twist when high concentrations of clay were encountered. Two years previously VAALCO installed the Avouma platform, and given the similar geology, opted to forego additional site investigation. Once drilling began, clay appeared. At times it was unconsolidated and inter-banded with weak layers of mudstone, siltstone, and sandstone. Since the hard mudstone and sandstone

sub-base of the formation ruled out a driven pile solution, the choice of raked piles tended to aggravate the problem. Once the socket was completed and before the drill bit and bottomhole assembly were removed, the hole was backﬁlled with a proprietary shaft-stabilization mud to support the unconsolidated clays and weak layers. This increased the socket stand-up time for safe pile insertion and grouting.

AnTech wellhead outlet stays cool in HP/HT wells AnTech has re-engineered its wellhead outlet to operate safely in the higher temperatures generated by high-pressure/hightemperature wells. The outlet responds to customer demand for an ATEX-certified tool that could be operated safely in today’s hotter wells, the company says. “With the dramatic rise in the number of HP/ HT wells, it was time to take the tool to the next level,” says Toni Miszewski, MD of AnTech. Previously, AnTech’s wellhead outlet was rated at a maximum Ta (ambient temperature) of 40° C (104° F), which indicates the maximum external temperature around the component; not the air temperature, with a maximum current of 26A. With these specifications, AnTech was able to offer the highest safety rating possible: T6, as the temperature of the device would never rise above 85° C (185° F), even if the outlet was operating at maximum Ta and current levels. AnTech plans to further develop its range of wellhead outlets. In 1Q 2009, the company expects to apply for certification of a

John Waggoner • Houston

wellhead outlet that will perform safely at a maximum temperature of 125° C (257° F).

Halliburton bridge plug designed for unsupported casing Halliburton has unveiled the Evo-Trieve bridge plug, a retrievable monobore plugging device that does not require a predetermined setting restriction for locating or sealing within the production completion. The new product is V0-qualified per ISO 14310 to 7,500 psi (0.14 mPa) at 275° F (135° C) and its design includes large slip and element footprints to provide pressure-holding capability in unsupported casing. Debris tolerance has been verified through a comprehensive flow loop testing program, the company says. The device can be deployed using conventional slickline with the DPU downhole power unit and can be retrieved with industry-standard GS pulling tools.

BJ Services soups up Seahawk deepwater cementing units In order to meet operators’ demands for reduced mixing and pumping times during deepwater cementing, BJ Services continues to develop higher horsepower cementing units with more conﬁguration options. In recent months a 1,600-bhp version and a 2,300-bhp model were developed to handle displacement tasks at higher rates and pressures. High-speed ﬁber optics let the equipment communicate remotely. Twin-mixing capabilities are being developed for the 2,300-bhp Seahawk unit for blending rates to 20 bbl/min to be deployed on an ultra deepwater drillship in the Gulf of Mexico in 2009.

ExxonMobil hits on Brazilian presalt well

AnTech’s wellhead outlet is ATEX-certified for a number of applications.

ExxonMobil has found hydrocarbons in Brazilian presalt formations near other major finds in the offshore Santos basin. The company reported Azulao-1 hit pay in the Azulao field of the BM-S-22 block in Santos on Jan. 16, 2009. ExxonMobil was not required to report estimates of potential recovery, but plans to continue drilling to target depth. Oil found in this area of Brazilian presalt formations can be at water depths of more than 2,000 m (6,562 ft) and 5,000 m (16,404 ft) below the seabed, making production both challenging and expensive. This Azulao field is located close to the Tupi and Carioca fields, both operated by the Brazilian national oil company Petrobras. Work is under way to pin down estimates, but Petrobras has previously stated that the presalt reserves from Tupi could range from 5-8 Bboe. The rig West Polaris drilled the hole. 

28 Offshore February 2009 • www.offshore-mag.com

0902off_28 28

2/11/09 2:07:48 PM

0902off_29 29

2/11/09 2:07:55 PM

Gene Kliewer • Houston

GEOSCIENCES

Africa TGS-NOPEC and West African Geophysical Seisdata Co. have opened a dedicated data storage, tape duplicating, and seismic data processing facility in Lagos, Nigeria, in the Lekki Peninsula area. In addition to storage and copying, the facility is able to recover data from older formats as well as provide workstations and high-speed communications for online data and information inquiry and retrieval. As for processing, the data center is networked to TGS Imaging’s processing nodes in Houston and Bedford, England, and can perform duplication and integrity checks, data transcription, sub-volume extraction, data split/merges, and pre-stack work, TGS says. The Seychelles government and Avana Petroleum have agreed to begin offshore exploration. Avana, with partner East African Exploration, is planning a 15,000-sq km (9,320-sq mi) program over three offshore blocks, A, B, and C, in water depths of 61 m (200 ft) to 2,438 m (8,000 ft). Early work will focus on the shallower waters. EAX is part of the Dubai-based Black Marlin Energy group that will conduct the geological and geochemical investigations over the next two years. Black Marlin Energy subsidiary Upstream Petroleum Services Ltd. expects to seek tenders for the planned 2D seismic survey over 2,000 km (1,243 mi) of the blocks over the next two years. Seismic data was gathered over 2,650 km (1,647 mi) in 2007 by the Seabird GeoMariner, the majority of which was carried out over blocks A and B. A well is planned in the second exploration period, possibly as early as 2011.

Latin America SCAN Geophysical ASA has signed a contract with GX Technology, an ION Geophysical subsidiary, to acquire up to 8,000 km (4,971 mi) of long-offset 2D data offshore Argentina. Some of that data will go to complete GXT’s ArgentineSPAN program.

Geosciences training in Africa moves forward The AfricaArray program designed to raise the capacities of African universities to train geoscientists is moving into Phase II of its 10-year program. Phase 1 (2004-2007), focused on revitalizing the geophysics program at the University of Witwatersrand. Phase II will run to 2010 and aims to build centers of excellence in geophysics at other universities in Africa and to expand a seismic network developed in Phase 1. The network consists of 30 seismic stations in 13 countries, mainly in eastern and southern Africa but with two stations in Cameroon in western Africa. In Phase II, the program will try to expand the number of seismic stations to 50, including 10 in West Africa, and will seek to expand the areas of geosciences to support research and training in groundwater hydrology, geochemistry, and geology, as well as meteorology. Since 2004, the AfricaArray program has raised about $3.5 million from the US National Science Foundation and $1.5 million or more from the South African National Research Foundation. Funding also comes from projects like one for the US Department of Energy’s National Nuclear Security Administration, for which students help identify natural seismic events.

SCAN says it will use its Geo Searcher with a 10,000-m (32,808-ft) solid streamer and special tuned source for the project. Ingrain, a Houston-based digital rock physics company, has opened a laboratory in Rio de Janeiro. “Demand for our services continues to grow,” says Henrique Tono, Ingrain’s CEO. “The opening of Ingrain’s lab in Brazil shows that technology leaders in the oil and gas E&P industry are embracing digital rock physics.” The Geological Products and Services division of TGS says it has started a multi-client interpretive study of offshore Brazil using the company’s proprietary Facies Map Browser (FMB) application. The FMB allows visualization of the distribution of and relationship between the various elements of a petroleum system within a depositional basin. This new study, funded by several oil companies, will use borehole and seismic data to map the development of depositional systems offshore Brazil in the form of sequence constrained environmental facies distribution maps. The ﬁrst phase of the project, the Santos Basin FMB, is scheduled for completion by end 1Q 2009. Additional phases in the Campos and Espirito Santo basins are scheduled for completion in 2009 and 2010.

Asia/Paciﬁc

3D GoM survey under way TGS-NOPEC Geophysical Co. says it plans to have data from its multi-client 3D “Hernando” survey covering 300 OCS blocks in the DeSoto Canyon area available before the March 2009 Gulf of Mexico lease sale. The MV BOS Arctic is scheduled to complete the acquisition in May 2009. Project deliverables will include pre-stack time migration as well as anisotropic Kirchhoff and wave equation pre-stack depth migrations. Gravity data is also being collected. “The Hernando survey will provide 3D data over a geological trend that was actively leased in the last Central Gulf of Mexico lease sale and also an area that has not been available for exploration during the last 20 years,” says Kim Abdallah, vice president of New Ventures for TGS.

Electromagnetic Geoservices ASA has won a contract valued at $7.5 million to apply its Clearplay Test service of 3D electromagnetic surveys to rank several hydrocarbon prospects offshore Malaysia. The prospects will be targeted by towing an EM source over receivers placed 1 - 2 km (0.6 to 1.2 mi) apart in a grid. The wide-azimuth, 3D EM data will then be processed to create resistivity maps and volumes. EMGS also has launched the world’s first purpose built EM survey vessel. The BOA Thalassa was build by Bergen Group Fosen and is on lease from owner BOA Offshore. EMGS says its survey capacity is increased by the vessel’s ability to handle a record number of receivers. The BOA Thalassa carries 100 receivers and can double this figure. Surveying efficiency and flexibility is increased by the vessel’s high speed, large fuel volume, extensive storage capacity, good fuel consumption, and extended weather window. A fully integrated spare equipment set and a new advanced onboard processing system will enhance the quality and improve the delivery time for EM data, according to EMGS. 

30 Offshore February 2009 • www.offshore-mag.com

0902off_30 30

2/11/09 2:07:57 PM

0902off_31 31

2/11/09 2:08:01 PM

TOP 10 DRILLING CONTRACTORS

Rig market adjusts to economy, oil price hile the downturn in the global financial markets is having an effect on just about every aspect of business around the world, the most important influence in the realm of petroleum remains the price of oil. At an oil price of over $100/barrel, energy companies had the luxury to increase exploration and production budgets and to drill more wells. With the increase in spending came a bump in demand for rigs, allowing drilling contractors to charge higher rates and to build a number of rigs on speculation. On the other hand, when the price of oil plummeted below $40/barrel, operators and contractors were forced to reevaluate their game plans. Oil and gas companies became more selective when it came to drilling wells, and contractors now have rigs under construction, some well advanced, but lacking contracts. To illustrate that point, a total of 180 rigs currently are under construction around the planet; however, according to ODS-Petrodata’s Offshore Rig Locator, of those rigs, 86 do not yet have contracts. Jackups are facing the toughest challenge as 54 of the 76 units under construction are without contracts. The continued push towards deepwater work will provide jobs for the floating rigs, hence, only 12 of the 55 semis and 16 of the 43 drillships under construction are uncontracted. If the price of oil can settle somewhere above $50 to $60/barrel, almost all of the new rigs eventually would find work. The extremely high day rates that some rigs started earning this year may come down some to coincide with the oil price, but at

Justin Smith

ODS-Petrodata

least more rigs will be working. At the current oil price, the demand for all types of offshore rigs will remain flat, according to ODS-Petrodata’s latest research. As new units are delivered into a flat market, fleet utilization will slide. Currently, worldwide offshore rig utilization stands at 87.6% as 647 of the world’s 739 jackups, semis, drillships, barges, tenders, submersibles, and arctic rigs are contracted.

US Gulf of Mexico From January 2008 to January 2009, the total fleet size in the US Gulf of Mexico declined from 125 rigs to 114, while the number of rigs under contract dropped from 96 to 86. Rig fleet utilization now stands at 75.4%. Most of the GoM decline has been in the jackup market, where utilization has dropped to 66.7%. As is typical in today’s deepwater focused industry, drillship utilization stands at 100%, and semisubmersible utilization is just above 96%. The region had a busy hurricane season in 2008, with hurricanes Gustav and Ike causing major disruptions. Three jackups were destroyed by Hurricane Ike, and a further three were heavily damaged but have since been repaired. Newbuild jackups Rowan Mississippi and J.P. Bussel have joined the fleet, helping to fill the gap left by the destruction of rigs. The jackup market in the US Gulf is expected to be flat in 2009. The jackup surplus

in the region stands at over a dozen rigs. In the US Gulf semisubmersible market, a small surplus will lead into a balanced supply/demand situation towards the end of the year, while the ﬂeet size should grow slightly. The drillship market is in balance, and if more rigs were available, work would be too. Day rates remain strong in the region. High-end jackups earned day rates of up to $195,000 a year ago, and are now earning between $130,000 and $220,000/day. The ﬂoating rig market is experiencing a substantial increase in day rates. Semis capable of operating in 5,001 ft (1,524 m) to 7,500 ft (2,285 m) are now pulling in day rates of $540,000 to $605,000. Day rates for drillships have also jumped considerably, as they are peaking at $650,000/day right now, up from the $525,000/day they were earning one year ago.

Latin America The number of jackups, semisubmersibles, and drillships available for charter in Latin America stands at 101, and of those rigs, 97 have contracts, for a utilization rate of 96.0%. In a region where most of the ﬂoaters are operating off the coast of Brazil, all 40 semis are contracted, as are all 11 drillships. Of the 50 jackups, the majority of which are working offshore Mexico, 46 have contracts. Demand for semis, jackups, and drillships in Central and South America is expected to grow through most of the next year, though jackup demand will likely dip slightly in late 2009. Much of the demand in the region will be driven by Petrobras’ exploration of its massive pre-salt reserves offshore Brazil. The

Top 10 drilling contractors ranked by total number of offshore mobile rigs per ﬂeet (excluding inland barges and platform rigs) Rig Owner

Total mobile rigs

Transocean Noble ENSCO Pride Diamond Offshore Seadrill Hercules Offshore Maersk Drilling Rowan PDVSA Total Source: ODS-Petrodata

140 61 51 46 45 43 38 30 29 27 510

Rigs contracted

Under construction

U.S. Gulf of Mexico

Latin America

Northwest Europe

West Africa

Middle East

Asia Paciﬁc

Rest of World

122 51 37 33 39 27 23 25 20 6 383

10 4 6 4 0 12 0 5 7 0 48

11 8 14 14 18 1 27 0 17 0 110

11 18 2 15 13 2 3 13 0 27 104

23 9 8 0 4 5 0 7 2 0 58

29 6 0 8 0 3 2 0 1 0 49

13 14 10 2 1 0 3 1 9 0 53

30 5 15 4 7 32 1 8 0 0 102

23 1 2 3 2 0 2 1 0 0 34

32 Offshore February 2009 • www.offshore-mag.com

0902off_32 32

2/11/09 2:37:40 PM

0902off_33 33

2/11/09 2:37:43 PM

TOP 10 DRILLING CONTRACTORS

market was expected to expand in the coming years with the addition of 28 ultra deepwater ﬂoating rigs contracted by Petrobras. However, economic uncertainty has delayed the contracting process. Day rates for jackups in Latin America have stayed about the same over the last several months. The current high for jackups is $200,000, up from $185,000 a year ago. Floating rigs, however, have seen a split in day rates, with ﬂoaters dipping some, while drillships have seen a major spike. Deepwater-capable semis are pulling in day rates up to $401,000, down from a maximum of $520,000 a year ago. Drillships, on the other hand, had a high of $320,000 12 months ago, but now are pulling in rates up to $650,000/day.

Europe The rig fleet offshore northwest Europe has seen little change over the last several years. The North Sea rig fleet is the same size now as it was a year ago, with a total of 74 units working. The region saw its streak of months and months with 100.0% fleet utilization end this year, and currently 73 of the 74 rigs are contracted, for a utilization of 98.7%. One of the 37 semis does not have a contract, but all 35 jackups have contracts, as do both drillships that are in the region. Many smaller operators in the area will be highly susceptible to lower oil prices and the global economic crisis. Average demand for jackups is expected to fall, as small operators hire a large portion of the North Sea jackup market. However, demand for higher specification semisubmersibles used by some companies will likely grow over the same period. An active UK licensing round may help buoy the market in the future. While fleet size and utilization in the North Sea has not changed much over the last year, the top of the range of harsh standard and high specification jackups are earning over 30% more now than be-

2009 Offshore Design and Construction Training Courses Now Available These courses are specifically designed for technical staff, operations management and business professionals. Both basic and advanced courses are available.

Worldwide mobile offshore drilling rig supply and demand 1,000 900

Total util % Total supply Contracted

100 90

800

700

600

500

50 40

400 Jan. 02 Jan. 03 Jan. 04 Jan. 05 Jan. 06 Jan. 07 Jan. 08

fore. They are earning a peak rate of $405,000/day, up from a high of $300,000/day this time last year. Semis have also seen an increase from the $350,000/day to $493,000/day they were making last year, and are now earning day rates between $410,000 and $530,820.

Mediterranean/Black Sea All but one of the 27 rigs in the Mediterranean/Black Sea region are under contract, for a ﬂeet utilization rate of 96.3%. Of the 27 rigs in the region, 23 are actually working. The one rig not contracted is jackup GSP Saturn, which is at a shipyard in Constanta, Romania, being converted into a cantilever rig with specs similar to another jackup, GSP Jupiter.

“𰀾𰀕𰁛𰁚𰁚𰁡𰀕𰁝𰁖𰁥𰁥𰁮𰀕

𰁗𰁚𰁘𰁖𰁪𰁨𰁚𰀕𰁞𰁩𰀕𰁬𰁖𰁨𰀕𰁨𰁤𰀕𰁚𰁖𰁨𰁮𰀕𰁩𰁤𰀕𰁢𰁤𰁫𰁚𰀕𰁩𰁤𰀕𰀷𰁪𰁥𰁖”

Courses given in North America, Europe and Southeast Asia. For a complete course schedule go to www.jmcampbell.com/OSM FREE subscription to the Campbell Tip of the Month at www.jmcampbell.com/TIP4

𰀹𰁤𰀕𰁮𰁤𰁪𰀕𰁬𰁖𰁣𰁩𰀕𰁩𰁤𰀕𰁢𰁤𰁫𰁚𰀕𰁩𰁤𰀕𰁩𰁝𰁚𰀕𰁬𰁤𰁧𰁡𰁙𰃉𰁨𰀕𰁡𰁖𰁧𰁜𰁚𰁨𰁩𰀕𰁞𰁣𰁩𰁚𰁧𰁣𰁖𰁩𰁞𰁤𰁣𰁖𰁡𰀕𰁚𰁭𰁥𰁖𰁩𰁧𰁞𰁖𰁩𰁚𰀕𰁝𰁚𰁖𰁡𰁩𰁝𰀕𰁞𰁣𰁨𰁪𰁧𰁖𰁣𰁘𰁚𰀕𰁥𰁧𰁤𰁫𰁞𰁙𰁚𰁧𰀕𰁖𰁣𰁙𰀕𰁖𰁫𰁤𰁞𰁙𰀕𰁖𰁡𰁡𰀕𰁩𰁝𰁚𰀕𰁝𰁚𰁖𰁙𰁖𰁘𰁝𰁚𰁨𰀴𰀕𰁉𰁤𰀕𰁜𰁚𰁩𰀕𰁩𰁝𰁚𰀕𰁛𰁚𰁚𰁡𰁞𰁣𰁜𰀡𰀕𰁩𰁝𰁚𰁧𰁚𰃉𰁨𰀕𰁤𰁣𰁡𰁮𰀕𰁤𰁣𰁚𰀕𰁣𰁪𰁢𰁗𰁚𰁧𰀕𰁩𰁤𰀕𰁘𰁖𰁡𰁡𰀣𰁈𰁞𰁢𰁥𰁡𰁚𰀕𰁩𰁧𰁖𰁣𰁨𰁛𰁚𰁧𰀕𰁤𰁛𰀕𰁘𰁤𰁧𰁥𰁤𰁧𰁖𰁩𰁚𰀕𰁘𰁤𰁫𰁚𰁧𰀕𰀸𰁖𰁡𰁡𰀕𰀠𰀩𰀩𰀕𰀝𰀥𰀞𰀕𰀦𰀧𰀬𰀨𰀕𰀧𰀥𰀭𰀧𰀥𰀥𰀕𰁤𰁧𰀕𰁫𰁞𰁨𰁞𰁩𰀕𰁬𰁬𰁬𰀣𰁗𰁪𰁥𰁖𰀢𰁞𰁣𰁩𰁡𰀣𰁘𰁤𰁢𰁎𰁤𰁪𰁧𰀕𰁘𰁖𰁡𰁡𰁨𰀕𰁬𰁞𰁡𰁡𰀕𰁗𰁚𰀕𰁧𰁚𰁘𰁤𰁧𰁙𰁚𰁙𰀕𰁖𰁣𰁙𰀕𰁢𰁖𰁮𰀕𰁗𰁚𰀕𰁢𰁤𰁣𰁞𰁩𰁤𰁧𰁚𰁙𰀣𰁉𰁝𰁚𰀕𰁖𰁗𰁤𰁫𰁚𰀕𰁚𰁭𰁖𰁢𰁥𰁡𰁚𰀕𰁙𰁧𰁖𰁬𰁨𰀕𰁛𰁧𰁤𰁢𰀕𰁩𰁝𰁚𰀕𰁚𰁭𰁥𰁚𰁧𰁞𰁚𰁣𰁘𰁚𰁨𰀕𰁤𰁛𰀕𰁖𰀕𰁣𰁪𰁢𰁗𰁚𰁧𰀕𰀕𰁤𰁛𰀕𰁤𰁪𰁧𰀕𰁢𰁚𰁢𰁗𰁚𰁧𰁨𰀕𰁤𰁧𰀕𰁨𰁩𰁖𰁛𰁛𰀰𰀕𰁞𰁩𰀕𰁞𰁨𰀕𰁣𰁤𰁩𰀕𰁞𰁣𰁩𰁚𰁣𰁙𰁚𰁙𰀕𰁩𰁤𰀕𰁧𰁚𰁥𰁧𰁚𰁨𰁚𰁣𰁩𰀕𰁩𰁝𰁚𰀕𰀕𰁙𰁚𰁩𰁖𰁞𰁡𰁨𰀕𰁤𰁛𰀕𰁖𰁣𰁮𰀕𰁨𰁥𰁚𰁘𰁞𰁛𰁞𰁘𰀕𰁞𰁣𰁙𰁞𰁫𰁞𰁙𰁪𰁖𰁡𰁨𰀕𰁤𰁧𰀕𰁩𰁝𰁚𰁞𰁧𰀕𰁘𰁞𰁧𰁘𰁪𰁢𰁨𰁩𰁖𰁣𰁘𰁚𰁨𰀣

0902off_34 34

2/11/09 2:37:45 PM

0902off_35 35

2/11/09 2:37:47 PM

TOP 10 DRILLING CONTRACTORS

The rig fleet in the region is primarily jackups, with six semisubmersibles and one drillship working there as well. All of the floaters are operating in Mediterranean waters, and a number of jackups are finding work in the Black Sea. Egypt leads the region with nine of the 23 active rigs, but several other countries see an increase in activity. Libya and Italy both have more rigs operating in their waters than a year ago, with five now off Libya and four offshore Italy. One country that rarely sees any offshore exploration is Israel, but currently semisubmersible Atwood Hunter is drilling there for Noble Energy. Both rig supply and demand are expected to remain flat over the next 12 months and nearly in balance, but very small deficits could pop up in the semi and drillship markets late in 2009, with a small surplus in the jackup market.

West Africa West Africa offshore rig ﬂeet utilization is at 100.0% for drillships, 92.3% for jackups, and 91.7% for semis. Overall, utilization in the area stands at 93.2%, with 55 of the 59 rigs in the region having contracts. West Africa offshore rig demand is expected to grow. The demand for jackups, semis, and drillships is expected to rise by about half a dozen rigs each over the next

year. However, equipment constraints, particularly in the ﬂoating rig market, will cause delays in some drilling programs. Day rates off West Africa are some of the highest worldwide. Jackups are earning between $148,000 and $244,000, which are prices that have not changed much in the past few months. Semisubmersibles experience a wide range of day rates, with semis with water depth capability of up to 5,000 ft (1,524 m) earning from $365,000 to $495,000/day. However, deeper rated semis are pulling in day rates between $620,000 and $650,000. Drillships are earning $450,000 to $495,000/day.

Middle East With 96 of 104 mobile offshore rigs under contract in the Middle East, the region’s offshore rig ﬂeet utilization rate is 92.3%. Due to the shallow waters through out the Middle East, all the 104 rigs are jackups. Outside the US GoM, the Middle East has some of the lowest day rates in the world. Day rates in the region actually have taken a slight downturn over the last year. While the low end of the range has improved to $107,000/day, up from $90,000 a year ago, the larger jackups are pulling in a maximum of only $161,595, which is a drop of nearly $40,000/day compared to one year ago.

The most active operators include Saudi Aramco with 29 offshore rigs under contract, followed by Adma-Opco with nine, and Maersk Oil with six. Jackup demand in the region is expected to climb by over 20 rigs over the next year, and a supply shortfall may develop.

Caspian Sea Exactly half of the 12 rigs in the Caspian Sea area are under contract. Of the 12 rigs in the Caspian, six are semisubmersibles and six are jackups. Four rigs in Azerbaijan are cold stacked, one more there is warm stacked, and one in Kazakhstan is hot stacked. The remaining rigs are working for operators BP, SOCAR, Dragon Oil, Lukoil, and Petronas Carigali. Construction has ﬁnally been completed on COSL-managed semi Iran Alborz in Iran after years of setbacks. It currently is undergoing acceptance testing before it is scheduled to begin working for NIOC in February, but there is no guarantee it will make that deadline.

Asia/Australia In the Asia/Australia region, 106 of the 110 jackups, semisubmersibles, and drillships are under contract for a utilization rate of 96.4%. Only four jackups are without contracts at presstime. continued on page 97 ...

TO RQFORCE ™ LETOURNEAU TECHNOLOGIES™

AC T R AC T I O N M OTO R S THE MOST PEAK TORQUE Available in 400, 550, 1150, and 1500 hp models. The LeTourneau™ Torqforce motors are designed for drilling, therefore you can depend on them for the toughest applications.

LONG LIFE. SUPERIOR RELIABILITY. LeTourneau Torqforce motors are built with more metal and thoroughly tested so you can count on every motor day-in and day-out.

OUR HEAVY-DUTY BULLSHAFT™ Our Bullshaft™ is constructed to better withstand torsional forces that lead to shaft failure and can tackle the demands of a wide range of beltdriven equipment.

www.letourneautechnologies.com 832-782-6500

0902off_36 36

2/11/09 2:37:48 PM

NEW CRUISER ™ TRACTOR

VERNON ™ PIPE CUTTING MACHINES

TO MEET CRITICAL OFFSHORE REQUIREMENTS. Lincoln Electric’s advanced Power Wave® equipment platform, Lincolnweld® submerged arc wire and flux and Vernon Tool™ cutting equipment deliver superior fit-up and welding performance on typical offshore applications, such as fixed and mobile rig construction, TKY joints, topside structural fabrication and many more.

SUBMERGED ARC CONSUMABLES

For a custom welding solution that delivers reliable performance while meeting the rigorous demands of the offshore industry – choose Lincoln.

0902off_37 37

2/11/09 2:37:51 PM

TOP 10 DRILLING CONTRACTORS

Global offshore prospects remain strong John Westwood Steven Kopits

Douglas-Westwood

e have just lived through the most volatile year in the history of the oil industry, with spectacular highs and crashing lows. After such a tumultuous year, what can we expect

in 2009? In the near-term, the oil business will suffer the effects of the global recession, primarily as a result of falling demand in the US and other developed countries. How deep and how long the recession will be remains to be seen, but the high oil prices witnessed in the first half of 2008 are unlikely to recur in the coming year. Analysts differ in their views, but most of them place oil prices in the $40-$65 range for this year. Consequently, short term oil industry dynamics likely will be subdued. At the same time, Douglas-Westwood’s longer term view of fundamentals remains essentially unchanged. The global economy will recover and China will resume its irrepressible drive towards modernization. This growth, and the growth it engenders in other developing economies, will drive energy consumption forward at a solid pace for many years to come. And the world will remain dependent on hydrocarbons well into the future. In 2007, 35% of primary energy demand came from oil—nearly 60% from hydrocarbons as a whole—and we do not see that changing materially over time. There are alternative energy sources, of course, but all of these have their own issues. Wind is limited by its intermittency. Sometimes the wind fails to blow. For example, the extreme cold of recent weeks led to a “wind drought” lasting many days in the UK. Although wind is an important new source of power, it cannot be called upon with the flexibility or certainty of gas-fired plants, and power storage solutions will be required to see wind reach its full potential. Solar remains expensive, and is limited similarly by available sunshine. As for wave and tidal power, the technical challenges presented by the relentless pounding of the ocean continue to bedevil industry. Nuclear is likely to be a critical component of our future energy picture, but the lead times are staggering, with the lag

Some 157 offshore rigs on order (present population 703 inc C.S.)

from project concept to realization reaching up to a decade. At the same time, the incumbent US ﬂeet of reactors will be half a century old or older by the time the next generation nuclear capacity connects to the grid. New nuclear plants may be only enough—if we are lucky—to replace the existing ﬂeet as it retires. Consequently, there are no alternatives on the horizon today which can act as a “game changer” to displace the wide-scale use of oil. Nothing, absolutely nothing, can match oil as a low cost, energy-dense, safe, and portable fuel. Pending some unexpected technological breakthrough, oil and gas will remain center-stage for many years to come. In the short term, however, global E&P spending is likely to decline. For 2009, Barclay’s Capital has forecast a 12% drop from 2008 levels. However, the 2009 forecast, at $400 billion, is not really much different from the spend

in 2007. Investments remain near historically high levels because the industry has suffered from many years of low capital expenditure levels. Throughout the ’80s and ’90s, investments which are needed today were deferred. Putting additional assets into play has proven both expensive and time-consuming. This is particularly true of offshore E&P activity. The rig market, for example, remains notably tight. With the exception of a minor easing for jackups, offshore rig utilization rates all are higher than they were a year ago when oil was over $100/barrel. Deepwater day rates also continue near all-time highs. Of course, there have been limited cancelations of rig orders and leases, primarily due to credit limitations. We see vulnerabilities, not so much at ongoing operations in big companies, but rather at smaller E&P companies more exposed to credit markets and other types of financing. Such concerns may spread if low oil prices persist, but for now, the offshore business has held up remarkably well. In a way, this is unsurprising. IOCs are experiencing increasing difficulty in replacing reserves. Onshore reserves in non-OPEC countries are largely carved up, and OPEC reserves are almost entirely controlled by NOCs. For the oil majors, finding the giant fields they need to make their economics work will tend to drive them offshore, and in particular into deepwater. That is where the major new discoveries

38 Offshore February 2009 • www.offshore-mag.com

0902off_38 38

2/11/09 2:37:53 PM

0902off_39 39

2/11/09 2:37:57 PM

TOP 10 DRILLING CONTRACTORS

are likely to be. As a case in point, ExxonMobil recently announced a potentially major subsalt find off the coast of Brazil. Of course, offshore finds are increasingly important to NOC’s as well. Pemex, Petrobras, and CNOOC all recently announced hefty increases in their offshore budgets, despite low oil prices. They realize that a short period of high investment activity probably will not be enough to meet the world’s growing demand for energy. If we allow global decline rates at around 4%, approximately 3-4 MMb/d of oil production must be replaced every year. Incremental oil finds will be needed, even if demand stays level. Second, comparatively low oil prices do not necessarily mean that oil industry economics have been undermined. We estimate that many operators are able to go forward with offshore projects at or near current prices. For example, Petrobras has indicated that its deepwater projects are economically feasible in the range of only $37-$42 per barrel of crude. Of course, offshore activity is not immune to the recession. Overall, we expect growth to flatten before it re-accelerates around 2011. We expect capex to ease, off perhaps 3% this year. Looking ahead longer term, we anticipate growth in expenditure in most regions with specific exception of Western Europe, due to the maturity of the North Sea area. But in aggregate, deepwater drilling and deepwater gas production are projected to be vibrant industry sectors. Another strong growth story is opex. Opex continues to ramp up, whereas capex tends to cycle. So, we find the whole operations area as an attractive business sector. Overall in the next few years, deepwater capital expenditures should reach new heights. We see large amounts of spending, nearly $140 billion over the next five years. We note that those figures exclude the Brazilian subsalt fields, as much of Brazilian spending and development will be beyond this time frame. Deepwater will need new equipment like FPSOs, which will continue to dominate expenditures, reaching $4 billion in 2009 and more than doubling by 2013. Subsea production will also expand. Subsea spending will more than double in the next five years compared to the previous five years. Growth is being driven by not only by the general migration to deepwater, but also by the increasing

number of marginal fields and single-well tie-ins. We also see a very strong growth in ROVs, with the fleet growing from approximately 500 today to around 700 by 2020. Annual spends should exceed $400 million, and the related operations market will grow from about $1.6 billion to about $2.4 billion. And finally, after many years, subsea processing is becoming a reality. We expect to see 186 subsea boosting applications over the next 10 years, as well as many separation systems and multi-phase meters. 

40 Offshore February 2009 • www.offshore-mag.com

0902off_40 40

2/11/09 2:37:58 PM

0902off_41 41

2/11/09 2:38:02 PM

S P E C I A L R E P O R T: T H U N D E R H O R S E

Thunder Horse:

Pushing the technology frontier Research, development leading new era in deepwater E&P Ray Viator

n December 2008, BP successfully started production from the third and fourth wells at the Thunder Horse South field in the US Gulf of Mexico with production in excess of 200,000 boe/d. The company plans to start-up additional production from wells in the Thunder Horse North field this year. BP operates Thunder Horse with 75% ownership. ExxonMobil has 25%. “Thunder Horse’s current production is a significant new source of US domestic energy, and is the second largest producing oil field in the US,” says Neil Shaw, BP senior vice president for Gulf or Mexico. “Thunder Horse has pushed the frontiers of deepwater technology that will be critical to our next phase of deepwater projects and to supplying America’s energy needs.” Sitting in 6,000 ft (1,829 m) of water about 150 mi (241 km) offshore, the Thunder Horse production-drilling-quarters (PDQ) semisubmersible is the largest production semi ever built, with a total displacement of 130,000 tons (117,934 metric tons). The topsides area of Thunder Horseis the size of about three football fields, and is packed with equipment and systems to treat and export 250,000 b/d of oil plus associated gas. “Thunder Horse has set new levels for deepwater exploration and production,” says Andy Inglis, BP’s chief executive of Exploration and Production. “With scores of new pieces of equipment or processes incorporated into the project, Thunder Horse has driven research and development efforts in many areas, including imaging and reservoir surveillance, drilling and completions equipment, and subsea and topsides production equipment.”

Technology evolution When Thunder Horse was discovered in 1999, much of the technology necessary to develop the field did not exist. There was a significant prize but getting it out of the ground safely and efficiently would require

Pictured from left to right is BP’s semisubmersible production platform Thunder Horse and Heerema’s semisubmersible construction vessels. Photo credit: 2008 BP Imageshop/Marc Morrison.

a major evolution of the technology. “Explorers have always gone beyond the limits and our engineers have always stepped forward to deliver solutions that seemed impossible at the moment of discovery,” says Shaw. Every major feature of Thunder Horse – from discovery to production – has required BP and the industry to develop new capabilities, systems, and equipment, and required a combination of applied research and development, discipline, and focus, says Dan Replogle, Thunder Horse vice president. “The challenges of Thunder Horse brought out the best in our people and the best in the industry.” Harnessing Thunder Horse posed challenges in almost every aspect of development, Replogle says. With this level of size and scale, integration was critical to success. “Everything is interrelated and, as a result, you can’t do anything in isolation. This requires a very well deﬁned and coordinated approach involving every aspect of a project as complex as Thunder Horse. Because of the enormity of the project, you

can’t have a small problem. Even small issues can quickly magnify because of the compounding effect.” The list of challenges began with its location in ultra deep waters with both loop currents and the threat of hurricanes. The project also was forced to contend with reservoir temperatures up to 270º F (132° C), pressures up to 18,000 psi (124 MPa), and the sheer size of the reservoir with ﬂow rates of up to 50,000 b/d of oil/well. As a result, Thunder Horse required larger bore tubing inside the wells than is normally used in the Gulf of Mexico. Constructed of high-strength materials, the tubing reached up to 7 in. (18 cm) in diameter.

Corralling the subsurface The Thunder Horse South ﬁeld features a four-way structural closure while the North ﬁeld is a three-way structural closure. The development plan targeted three major reservoirs ranging from 18,000 ft to 30,000 ft (5,486 m to 9,144 m) in measured depth. “We knew we had world-class reservoirs but at the time subsalt imaging was relatively new in the industry,” says Greg Arnold,

42 Offshore February 2009 • www.offshore-mag.com

0902off_42 42

2/11/09 2:38:06 PM

When it’s a question of Shallow Section Risks...

...Ask Fugro Fugro’s Global GeoConsultancy can now provide your development project with the expertise you need to accurately quantify risk and optimise design.

Utilising the key disciplines of Geophysics, Geology and Geotechnical Engineering, any site can be critically assessed and the implications for wells and facilities analysed and mitigated. • Expertise in all types of geohazard • Risk assessment focused on specific foundation installation and soil types • World-class resources and expertise available to your development • Global data acquisition matched by global data interpretation • Optimised foundation design and layout Fugro GeoConsulting Ltd, Fugro House, Hithercroft Road Wallingford, Oxfordshire, OX10 9RB, UK Tel: +44 870 4021300, Fax: +44 870 4021399 Email: info@fugro.co.uk Fugro GeoConsulting Inc., P.O. Box 740010, 6100 Hillcroft Houston TX 77081, USA Tel: +1 713 369 5800, Fax: +1 713 369 5811 Email: info@fugro.com

www.fugro.com

NO OTHER COMPANY CAN PROVIDE THE SAME COMPREHENSIVE RANGE OF GEOTECHNICAL, SURVEY AND GEOSCIENCE SERVICES

0902off_43 43

2/11/09 2:38:10 PM

S P E C I A L R E P O R T: T H U N D E R H O R S E

Pictured here is a rendition of the subsea architecture. A total of 22 production wells and 11 water injectors are planned for both North and South Field development for Thunder Horse. The final complement will depend on reservoir performance. Photo credit: 2008 BP Imageshop/Marc Morrison.

Thunder Horse resource manager. Project plans also included water injection capability for reservoir pressure support and enhanced recovery. Real-time monitoring and analysis of production rates is required to keep the processing facility fully loaded and to forecast when water breakthroughs might occur in the reservoir. Each well is monitored in real time. “Given the rate of production from each well, we recognized early on that even small changes in downhole pressure or temperature could be magnified and have significant impact on our production plans,” says Arnold. While other GoM fields may be monitored with single gauges, for example, the subsurface team incorporated three gauges plus two independent controls on each of the three gauges for each Thunder Horse well. “We built redundancies into the system to ensure we would be able to get reliable information throughout the life of the wells,” Arnold says. Initial results from the first four wells have exceeded start-up expectations for connected volume and energy in the reservoir. Since oil production began, Arnold says, his team also has begun to focus on identifying unswept pockets of oil. “The more information we have, the more accurate we can be in targeting those areas and in ensuring that we maximize production throughout the reservoir.”

Drilling in a new environment The Thunder Horse team has been drilling and completing wells in the area since the original exploration well in 1999. In 6,400 ft (1,951 m) of water, the ﬁeld’s wells reach to about 29,000 ft (8.839 m) measured depth and 26,000 ft (7,925 m) TVD. The wells team has overcome challenges associated with high-pressure/high-temperature (HP/HT) drilling. Some wells, for example, require up to eight casing strings in order to drill in the narrow pore-pressure-tofracture gradient window. Now that production has started, the team is addressing the challenges of drilling through depleted zones. Thunder Horse required over 100 serial No. 001 items in the ﬁrst completion, and intelligent wells are being planned for future development. The completions require a wellbore with large diameter tapered casing strings to accommodate the 7-in. (17.78-cm) tubing and large surface casing/subsurface safety valves. In addition, the different reservoirs require multiple completion techniques including cased

and perforated, frac pack and High Rate Water Pack sand control, and multi-zone completions. Sophisticated metallurgy, such as nickel alloys and 25-chrome, was required in the critical completion components to prevent corrosion associated with hydrogen sulfide contamination from fieldwater injection. The rigs used for Thunder Horse are among the most advanced in the industry, says Charles Holt, Thunder Horse wells operations manager. Discoverer Enterprise, a fi fth generation drillship, was selected for Thunder Horse because of its capabilities. In addition, the Thunder Horse facility and its twin derricks were designed to address the field’s technical challenges. The rig’s capabilities, such as derrick capacity, mud volumes, and pumping capability, equals or exceeds those of any other rig. Its derrick capability allows multiple activities simultaneously, Holt points out.

Pushing subsea technology “We’ve focused on learning more about materials and how they operate in this environment with high temperatures and high pressure, as well as how all of those materials interact with one another,” says Karen Veerkamp, Thunder Horse subsea engineering manager. One of the top technological developments to arise from the Thunder Horse project is the water injection flexible riser system. “If you were to chart the industry’s use of flexible injection risers for depth, diameter, and pressure ratings, Thunder Horse has increased it by a factor of two,” Veerkamp says. The program has been delivered from design to prototype, to manufacture and to factory acceptance without a problem. Since work began on Thunder Horse, there have been technology developments on several fronts, and BP has worked to incorporate those into the project over time. For example, subsea multi-phase flow meters which were not highly developed in 2001 now are being incorporated into engineering plans for the Thunder Horse North field. “Over the past few years, there have been great advances in a number of areas, including insulation systems for pipelines and subsea equipment, coating systems, and welding. In some ways, Thunder Horse has driven a lot of new development,” Veerkamp says.

Operating at a new level The size, scale and complexity of Thunder Horse also had unprecedented implications for facility stafﬁng and operation. “When you think about very large, complex projects, Thunder Horse is at the next higher level,” says McDaniel. “This is state-ofthe-art technology and equipment. It’s not your average offshore facility, so we invested signiﬁcantly in training programs for our employees and operators, many of whom have come from smaller facilities.” The training program included extensive use of BP’s Advanced Collaborative Environment (ACE), which allows a unique level of simulation and interaction. “ACE gave us the ability to virtually start up the facility several hundred times in a simulated environment,” McDaniel says. ACE connects different locations and assets with real-time monitor-

44 Offshore February 2009 • www.offshore-mag.com

0902off_44 44

2/11/09 2:38:11 PM

Driving economies This is one of our ships That That That That That

is exploring the oceans are concealing the structures are hosting the reservoirs will provide the energy will supply your customers

To keep global economies moving

marine geophysical services www.waveďŹ eld-inseis.com 0902off_45 45

2/11/09 2:38:13 PM

S P E C I A L R E P O R T: T H U N D E R H O R S E

Thunder Horse Fast Facts • Located about 150 mi (241 km) southeast of New Orleans in Mississippi Canyon at a water depth of 6,050 ft (1,844 m) • Largest semisubmersible facility in the world at 130,000 metric tons (143,300 tons) displacement • Has a deck load capacity of 40,000 metric tons (44,092 tons) • Designed to process and export up to 250,000 b/d of oil and 200 MMcf/d of natural gas • Production is from reservoirs between 14,000 to 19,000 ft (4,265 to 5,790 m) below the seabed • Reservoir pressures range from 13,000 to 18,000 psi (approx 885 to 1,255 bar) • Reservoir temperatures range from 190º to 270º F (88º to 132º C) • Achieved 15 million man hours of DWRI • The topsides area of the Thunder Horse PDQ is the size of three football fields • The installed power generation capacity totals 100 MW – enough to supply a town of around 80,000 homes, and the biggest offshore power generation plant in the world.

Thunder Horse Serial No. 001s • Of the 32 major components in a 140-mm (5 1/2-in.) diameter Thunder Horse completions string, 18 of these are classed as “Serial Number Ones” • A further seven were existing designs that had to be modified • And by the time the operations team had developed ways to install and operate the completions strings, a further 89 Serial Number Ones were notched.

Thunder Horse is equipped with a state-of-the-art fifth generation dual drilling rig. Photo credit: 2008 BP Imageshop/Marc Morrison.

ing technology and video conference capability through a fiber-optic feed that connects the Houston office with all of BP’s assets in the GoM. It brings together the right information, to the right people, at the right time, enabling people to work collaboratively regardless of distance, leading to more efficient decision-making, says BP. ACE also has improved productivity, training, and overall operational performance, BP says. McDaniel’s team also focused heavily on developing a robust operations readiness plan and system integration. When his team started that process, there were 900 action items to finalize before Thunder Horse came online. “We documented the entire process and had it vetted by experts in each discipline and technology throughout BP,” McDaniel says. “We then had a thorough review with our co-owner, ExxonMobil. In the end, we believe we delivered a best-in-class operations readiness plan.” The result, McDaniel says, was that the actual start-up was the smoothest he has ever been associated with.

Overcoming challenges As work progressed to prepare the facility for production in 2005, the giant semisubmersible was found to be listing following evacuation for Hurricane Dennis. The incident was not the result of hurricane damage. While complex, the basic issue was related to the ballast hydraulic control sys-

tem. BP tackled the hydraulic control system problems and took action to ensure the platform to be storm-safe when unmanned. Despite the punishment doled out by major hurricanes since, the platform has performed without incident. In 2006, BP discovered weld failures caused by hydrogen embrittlement during pre-commissioning tests on critical subsea components. The welds themselves and the completed manifolds had passed all of the normal industry standard tests, inspections, and regulatory requirements. To ﬁx the weld failures, Veerkamp says, BP went back to ground zero to reengineer and to rebuild the subsea system to meet the Thunder Horse operating conditions. Knowledge gained will be important to future deepwater HP/HT developments around the world, says BP.

Looking to the future “Thunder Horse is already making an important contribution to supplying the US with safe, secure energy supplies, and it will continue to do so for the next 20-25 years,” says Inglis. “But the impact of Thunder Horse goes beyond its significant production levels because the technology that has been developed for this giant field can also be applied to equally significant and promising fields elsewhere in the deep waters of the GoM. Thunder Horse will help usher in a new era in US exploration and production in the Gulf.” In many respects, Thunder Horse represents the first of a new generation of super challenging deepwater developments. The success of Thunder Horse also is encouraging as the industry looks ahead to exploring in the GoM’s Paleogene trend, a massive emerging play which has the potential to supplement the maturing Miocene trend and to maintain the basin’s production level. Some estimates put the potential of the Paleogene at over 50 Bbbl of oil in place with giant fields like BP’s Kaskida discovery. “The technology we have developed and the lessons learned from Thunder Horse are going to be invaluable as we develop this next wave of the GoM,” says Inglis. 

46 Offshore February 2009 • www.offshore-mag.com

0902off_46 46

2/11/09 2:38:14 PM

0902off_47 47

2/11/09 2:38:17 PM

ASIA

Miocene/basement fairway opens up alongside Bach Ho

Jeremy Beckman

Editor, Europe

Emerging prospects could extend underused facilities utput is building at Ca Ngu Vang, the first field in Vietnam’s Cuu Long basin to be developed as a third-party tieback to the Bach Ho offshore complex. Ca Ngu Vang (CNV), in Cuu Long basin block 9-2, was discovered by the Hoan Vu Joint Operating Co. (JOC), comprising PetroVietnam, PTTEP, and London-based SOCO International. At peak, the field should generate 20,000 boe/d of oil and wet gas, partly offsetting natural decline at Bach Ho, where the facilities currently operate at less than half their process capacity of 400,000 boe/d. To the west in block 16-1, the same partners are active as the Hoang Long JOC. Here they have established a major Miocene/Oligocene play fairway, and a potentially more prolific and deeper highpressure/high-temperature play.

Basement background Fractured basement granite is the setting for CNV, Bach Ho, and a series of other fields trending northeast to Su Tu Den and Su Tu Vang in block 15-1. Bach Ho is by far the biggest, having delivered well over 1 Bbbl of oil to date. Mobil, which operated most of this acreage in the early 1970s, was the first to recognize the potential for major structures following an extensive 2D seismic program. After the company’s forced exit in 1975, the Russian/Vietnamese venture Vietsovpetro took sole charge of exploration. According to Edward Story, SOCO CEO, “Vietsovpetro first developed the conventional Miocene reservoirs at Bach Ho. While drilling one unsuccessful Miocene well, they decided to keep on drilling into basement, where they discovered the unconventional granite basement that became the heart of the Bach Ho development and much of the excitement that followed in the Cuu Long basin.” When the first wave of European companies returned to Vietnam in the late 1980s, they focused on conventional reservoir targets in this basin and were largely unsuccessful. In the 1990s, the US lifted the trade embargo, and a further wave of exploration began. At that time PetroVietnam actively encouraged basement exploration, which led to discoveries such as JPVC’s Rang Dong in block 15-2. Later on, ConocoPhillips transferred pre-stack depth migration (PSDM) seismic techniques deployed to look through salt in the Gulf of Mexico to improve well placement in fractured basement prospects in block 15-1. “They also introduced deviated wells to basement development,” Story adds. None of these technologies were available early on for Bach Ho, where mounting water production has necessitated several re-development phases over the past two decades. Eventually Vietsovpetro was able to supplement its vertical wells with horizontal producers paired with injectors, and according to Antony Maris, SOCO’s vice-president, Operations & Production, learned how to pair these to stem water breakthrough.

Tieback arrangements In 2004, following mixed basement drilling results, the block 9-2 partners turned to PSDM to re-process seismic over the CNV

The CNV platform with the PVD-1 jackup alongside.

structure. The resultant appraisal well, CNV-3X, was much more productive, testing over 9,000 b/d of oil and 22 MMcf/d of gas from a granite basement interval of 2,000 m (6,561 ft). Two years later, the partners executed another successful test on CNV-4X, in the process setting a measured depth record – 6,330 m (20,767 ft) – for a Vietnamese well. Work on the $280-million development started in earnest early in 2007, with yards in Vietnam assembling CNV’s unmanned shallow water wellhead platform. Specialist vessels were then brought in to install the platform and the 25-km (15.5-mi) multiphase pipeline taking the field’s well stream to Bach Ho’s CPP3 process platform. In August that year, PetroVietnam’s newly commissioned jackup PVD-1 started drilling the first of six first-phase development wells. Four were on line when oil and wet gas started flowing in July 2008, with the fi fth well due to be completed last month. “We may add a seventh,” says Maris, “although that will depend on production performance.” The partners have no plans for further exploration on or around CNV, he adds, following an unsuccessful attempt to prove further reserves to the east. “These are standard deviated basement wells – nothing fancy,” Maris explains, “and the associated gas acts as a pump, so there is no need for downhole lift.” However, a water injector line has been put in alongside the multiphase line from CPP3 to provide pressure support. The Bach Ho CPP3 process installation controls operations on the CNV platform, also opening and shutting the wells. The third-party arrangements – which include a metering allocation system with a tariff mechanism – are all new to PetroVietnam, says Maris. “They

48 Offshore February 2009 • www.offshore-mag.com

0902off_48 48

2/11/09 2:54:56 PM

Your Source for Energy News, Research, and Insight. Yo

More Content. Global Energy Coverage. Introducing the NEW PennEnergy.com PennEnergy.com launches with even more valuable energy-centric content and easier, more efﬁcient navigation. The new web site provides the most complete and trusted source of energy-related topics including today’s news plus ten years of archived web and magazine content from PennWell’s award-winning energy publications.

Organized by Industry Segments and Topic Centers. Extensive research tools, white papers, and webcasts. Comprehensiveener gy-related ﬁnancial information. Original and sourced energy news. Product, equipment, and service information.

Make PennEnergy a part of your day and know what is happening in the world of energy.

0902off_49 49

PennEnergy.com 2/11/09 2:54:58 PM

ASIA

do accept gas already from JVPC’s Rang Dong field in block 15-2, but that simply flows through the Bach Ho trunkline system.” “CNV’s oil is more gaseous,” adds Story, “but for the Bach Ho team it is just a case of making slight adjustments to their process facilities.” Post-processing, the crude is stored on an FSO (there are three permanently on station at Bach Ho) before being sold on the international market. The processed gas stream heads through an existing pipeline to the Ding Ho terminal in southern Vietnam, where the liquids are stripped out for sale as LPG. “Ours is a very different, rich gas stream,” Story points out, “so we have had to set up gas allocation procedures with Vietsovpetro.” A sales agreement for the gas has still to be concluded, he adds. “However, in our case, the price for the gas is not as sensitive as what we are paid for the liquids.” SOCO expects 150 MMboe to be recovered from the field over its anticipated 20-year lifespan.

Miocene breakthrough Block 16-1, in average water depths of around 50 m (164 ft), has taken longer to appraise. Initially, the Hoang Long partners targeted shallower basement structures in the west of the block. Ngua-0-1X, their ﬁrst exploratory well,

Cuu Long basin map shows CNV-Bach Ho export route in block 9-2 and discoveries in block 16-1.

tested minor quantities of oil while drilling through multiple fracture systems. A well on the Voi Trang structure was more promising, ﬂowing 3,500 b/d of oil mainly from Oligocene and basement intervals, although a follow-up well was abandoned after encountering only oil shows in the Upper Oligocene. In 2005, the JOC turned its attentions to the

Miocene/Oligocene potential in the eastern part of block 16-1, with immediate payback. The TGT-1X well on the Te Giac Trang (TGT) prospect tested oil and gas at over 9,000 boe/d from the Miocene Lower Bach Ho (LBH) formation. An up-dip appraisal well ﬂowed at almost double that rate – 17,500boe/d – from Miocene LBH 5.2 and Oligocene intervals.

𰀯𰁆𰁆𰁓𰁈𰁏𰁒𰁅𰀀𰀥𰁎𰁇𰁉𰁎𰁅𰁅𰁒𰁉𰁎𰁇

𰀥𰁘𰁃𰁅𰁌𰁌𰁅𰁎𰁔𰀀𰁏𰁆𰁆𰁓𰁈𰁏𰁒𰁅𰀀𰁐𰁒𰁏𰁔𰁅𰁃𰁔𰁉𰁏𰁎

𰀤𰁏𰁗𰀀𰀨𰁙𰁐𰁅𰁒𰁌𰁁𰁓𰁔𰀇𰁓𰀀𰁗𰁏𰁒𰁌𰁄𰁗𰁉𰁄𰁅𰀀𰁒𰁅𰁎𰁏𰁗𰁎𰀀𰁆𰁏𰁒𰀀𰁅𰁘𰁃𰁅𰁌𰁌𰁅𰁎𰁃𰁅𰀀𰁉𰁓𰀀𰁂𰁕𰁉𰁌𰁔𰀀𰁏𰁎𰀀𰁄𰁅𰁌𰁉𰁖𰁅𰁒𰁉𰁎𰁇𰀀𰁐𰁒𰁏𰁄𰁕𰁃𰁔𰁓𰀀𰁔𰁈𰁁𰁔𰀀𰁏𰁆𰁆𰁅𰁒𰀚𰁳𰀀𰁅𰁘𰁃𰁅𰁌𰁌𰁅𰁎𰁔𰀀𰁐𰁒𰁏𰁔𰁅𰁃𰁔𰁉𰁏𰁎𰀀𰁳𰀀𰁓𰁔𰁒𰁅𰁎𰁇𰁔𰁈𰀀𰁁𰁎𰁄𰀀𰁒𰁅𰁓𰁉𰁌𰁉𰁅𰁎𰁃𰁅𰀀𰁳𰀀𰁄𰁅𰁍𰁏𰁎𰁓𰁔𰁒𰁁𰁔𰁅𰁄𰀀𰁐𰁅𰁒𰁆𰁏𰁒𰁍𰁁𰁎𰁃𰁅𰀀𰁏𰁖𰁅𰁒𰀀𰀓𰀐𰀀𰁙𰁅𰁁𰁒𰁓𰀀

𰀰𰀲𰀯𰀴𰀥𰀣𰀴𰀩𰀮𰀧𰀀𰀡𰀮𰀤𰀀𰀩𰀮𰀳𰀵𰀬𰀡𰀴𰀩𰀮𰀧𰀀𰀰𰀩𰀰𰀥𰀬𰀩𰀮𰀥𰀳𰀦𰀩𰀥𰀬𰀤𰀀𰀪𰀯𰀩𰀮𰀴𰀩𰀮𰀧𰀤𰀯𰀣𰀫𰀳𰀩𰀤𰀥𰀀𰀡𰀮𰀤𰀀𰀯𰀦𰀦𰀳𰀨𰀯𰀲𰀥𰀀𰀭𰀡𰀲𰀩𰀮𰀥𰀀𰀰𰀲𰀯𰀴𰀥𰀣𰀴𰀩𰀯𰀮

𰀤𰁏𰁗𰀀𰀨𰁙𰁐𰁅𰁒𰁌𰁁𰁓𰁔𰀀𰁉𰁓𰀀𰁁𰀀𰁔𰁒𰁁𰁄𰁉𰁎𰁇𰀀𰁎𰁁𰁍𰁅𰀀𰁏𰁆𰀀𰀨𰁙𰁐𰁅𰁒𰁌𰁁𰁓𰁔𰀀𰀬𰁉𰁍𰁉𰁔𰁅𰁄𰀀𰁗𰁉𰁔𰁈𰀀𰁒𰁅𰁇𰁉𰁓𰁔𰁒𰁁𰁔𰁉𰁏𰁎𰀀𰁎𰁕𰁍𰁂𰁅𰁒𰀀𰀒𰀙𰀔𰀗𰀒𰀔𰀗𰀌𰀀𰁈𰁁𰁖𰁉𰁎𰁇𰀀𰁉𰁔𰁓𰀀𰀲𰁅𰁇𰁉𰁓𰁔𰁅𰁒𰁅𰁄𰀀𰀯𰁆𰁬𰀀𰁃𰁅𰀀𰁁𰁔𰀀𰀤𰁉𰁁𰁍𰁏𰁎𰁄𰀀𰀨𰁏𰁕𰁓𰁅𰀌𰀀𰀬𰁏𰁔𰁕𰁓𰀀𰀰𰁁𰁒𰁋𰀌𰀀𰀫𰁉𰁎𰁇𰁓𰁂𰁕𰁒𰁙𰀀𰀣𰁒𰁅𰁓𰁃𰁅𰁎𰁔𰀌𰀀𰀳𰁔𰁁𰁉𰁎𰁅𰁓𰀌𰀀𰀭𰁉𰁄𰁄𰁌𰁅𰁓𰁅𰁘𰀌𰀀𰀴𰀷𰀑𰀘𰀀𰀓𰀡𰀧𰀌𰀀𰀥𰁎𰁇𰁌𰁁𰁎𰁄𰀎𰀀𰀴𰀭𰀀𰀴𰁒𰁁𰁄𰁅𰁍𰁁𰁒𰁋𰀀𰁏𰁆𰀀𰀴𰁈𰁅𰀀𰀤𰁏𰁗𰀀𰀣𰁈𰁅𰁍𰁉𰁃𰁁𰁌𰀀𰀣𰁏𰁍𰁐𰁁𰁎𰁙𰀀𰀈𰁨𰀤𰁏𰁗𰁶𰀉𰀀𰁏𰁒𰀀𰁁𰁎𰀀𰁁𰁆𰁬𰀀𰁌𰁉𰁁𰁔𰁅𰁄𰀀𰁃𰁏𰁍𰁐𰁁𰁎𰁙𰀀𰁏𰁆𰀀𰀤𰁏𰁗

0902off_50 50

𰀥𰁎𰁇𰁉𰁎𰁅𰁅𰁒𰁉𰁎𰁇𰁐𰁏𰁌𰁙𰁕𰁒𰁅𰁔𰁈𰁁𰁎𰁅𰁅𰁘𰁃𰁅𰁌𰁌𰁅𰁎𰁃𰁅𰀤𰁏𰁗𰀀𰀨𰁙𰁐𰁅𰁒𰁌𰁁𰁓𰁔𰀀𰁍𰁁𰁙𰀀𰁂𰁅𰀀𰁃𰁏𰁎𰁔𰁁𰁃𰁔𰁅𰁄𰀀𰁁𰁔𰀚𰀀𰀳𰁔𰁁𰁔𰁉𰁏𰁎𰀀𰀲𰁏𰁁𰁄𰀌𰀀𰀢𰁉𰁒𰁃𰁈𰀀𰀶𰁁𰁌𰁅𰀀𰀨𰁉𰁇𰁈𰀀𰀰𰁅𰁁𰁋𰀌𰀀𰀤𰁅𰁒𰁂𰁙𰁓𰁈𰁉𰁒𰁅𰀀𰀳𰀫𰀒𰀒𰀀𰀑𰀢𰀲𰀀𰀵𰀫𰀀𰀴𰁅𰁌𰀚𰀀𰀋𰀔𰀔𰀀𰀈𰀐𰀉𰀀𰀑𰀖𰀖𰀓𰀀𰀗𰀔𰀖𰀕𰀑𰀘𰀀𰀦𰁁𰁘𰀚𰀀𰀋𰀔𰀔𰀀𰀈𰀐𰀉𰀀𰀑𰀖𰀖𰀓𰀀𰀗𰀔𰀖𰀖𰀐𰀕𰀀𰀥𰀍𰀭𰁁𰁉𰁌𰀚𰀀𰁈𰁅𰁌𰁐𰀠𰁄𰁏𰁗𰁈𰁙𰁐𰁅𰁒𰁌𰁁𰁓𰁔𰀎𰁃𰁏𰁍𰀀

𰁗𰁗𰁗𰀎𰁄𰁏𰁗𰁈𰁙𰁐𰁅𰁒𰁌𰁁𰁓𰁔𰀎𰁃𰁏𰁍 2/11/09 2:54:59 PM

0902off_51 51

2/11/09 2:55:02 PM

ASIA

These and five further wells through mid2008, with average oil and gas flow of around 11,300 boe/d each, confirmed a potentially major structure. “TGT could be well north of 300 MMboe recoverable,” Story claims. The field comprises stacked clastic reservoirs in five fault blocks extending over 15 km (9.3 mi) from north to south within an 80-km (49.7-mi) long play fairway. In 2006, the Thang Long JOC in block 15-2/0-1 to the north, led by Talisman Energy, also proved a very small extension of TGT into its south-eastern waters. The next, and probably final, appraisal well on TGT could be a step-out on the flank of one of the fault blocks, says Maris. “This is a very subtle structure, with a large number of pay sands, so understanding what we have on the flanks is critical for injection capacity design for the development.” Concurrent with this program, in April 2007, the JOC decided to test the unrelated “E” prospect to the south of TGT, targeting a HP/HT Oligocene structure identified from new 3D seismic. This structure, also known as Te Giac Den (TGD), had been recognized in the early 1990s from 2D data acquired by Mobil two decades earlier. “It was thought to be gas, so it did not attract the same level of interest at the time as other prospects in the area,” Story explains.

Drilling operations onboard the PVD-1.

“But ConocoPhillips had shown more recently with discoveries such as Su Tu Den and Su Tu Trang in block 15-1 that the oil window in this play starts to widen the deeper you drill.” The TGD-1X well was also the ﬁrst drilled by the then newly commissioned PVD-1 drilling rig. It encountered oil and gas in two Oligocene clastic sequences separated by a vol-

canic layer, with 30 m (98.4 ft) of pay logged in the upper sequence. But operations had to be halted 22 m (72.2 ft) into the lower sequence after penetrating a high pressure zone beyond the rig’s safe operating capacity. Later that year the jackup Adriatic XI was brought in, fitted with a 15,000-psi BOP, to re-enter the well and drill a sidetrack towards fractured basement, where seismic interpretation had indicated a further 300 m (984 ft) of sediment. En route, the well had to be cased three times as it intersected different sands to prevent further downhole pressure problems. Operations continued well into 2008, progress towards the basement proving to be more time-consuming and costly than expected. Eventually the side track well was plugged back to 4,820 MD to allow two DSTs to be conducted in the HP/HT Oligocene interval. The first of these, below the volcanic layer, flowed gas and condensate; the second, higher up, recovered black oil, condensate, and gas with similar characteristics to output from CNV. Testing was hampered by downhole damage and limitations of the perforations, rendering flow rates meaningless. But the well did identify the presence of a working hydrocarbon system. “We were doing rank wildcat drilling in a difficult, high-pressure/high-temperature environment,” Story points out, “with

Ring joint for sealing & surveillance The efficient sollution for flanged connections

By pressure testing the flanges ring room. Correct installation will be verified. Indicator will monitore any future leakages. Time, cost and safety efficent

«Correct installation will be

Having too many leakages in flanged connections..

the flanges ring room.

verified by pressure testing Future leakages wil be monitored by an indicator» S TAT O I L

P.O.Box 484 - N-4291 Kopervik - Norway - Telephone +47 52 84 43 40 - Telefax +47 52 84 43 41

0902off_52 52

2/11/09 2:55:03 PM

Your pipeline should be going down, not your laybarge equipment. Go for uptime. Go with CRC-Evans.

Pipe handling, double jointing and coating equipment built offshore tough. As your pipeline takes the plunge, CRC-Evans helps keep your productivity up high. We have nearly 40 years experience working in offshore pipeline construction. We know what it takes for a project to be successful in this harsh environment, and weâ&#x20AC;&#x2122;re fully dedicated to delivering quality equipment specifically built for it. Every part, machine and system within our pipe handling, double jointing and joint coating lines are beefed up to be tougher and have larger operational safety margins than equipment designed for land. For example, we utilize advanced computer technology to calculate tensile, loading and other relevant forces to ensure everything we build is safe, sound and ready to stand up to offshore extremes. Our equipment has proven itself in the field, time after time. Plus you get the reassurance of working with a company that has served the offshore industry through thick and thin. And has the stability and worldwide infrastructure to be there when and where you need us, with a full spare parts inventory and expert service teams. Equipment up, pipeline down. Contact CRC-Evans and letâ&#x20AC;&#x2122;s make it happen. Tulsa, Oklahoma www.crc-evans.com USA: +1-918-438-2100

0902off_53 53

2/11/09 2:55:10 PM

ASIA

no geological benchmarks to go on. “Also, we were working with specialized equipment that had to be brought in from different parts of the world. And in this environment, you’re obliged to use either a brand new rig that hasn’t been shaken down, or an old rig. Having said, the PVD-1 has performed really well since re-deploying to CNV for development drilling.”

Regional setting “Throughout the Cuu Long basin,” Story explains, “there is a very rich, thick D-shale that serves as a source and seal for the whole basin. Pre-drilling, the risk on this project was having early migration of hydrocarbons to preserve reservoir porosity during burial. “Within the TGD structure, there are two different reservoirs above and below the volcanics separated by a volcanic interval. The reasons for our excitement are twofold: in the upper section, above the volcanics, we have black oil, with gas and condensate underneath. The hydrocarbons here are similar to those found in CNV. Beneath the volcanics, it is more like the gas-condensate present in Su Tu Trang.” Reservoir quality was poor as the well approached the sealing point in the structure, Story adds. “There appears to be a stratigraph-

ic element, with a sedimentary fan thickening to the north towards the TGT structure – it is hugely exciting.” He cites as analogies Buzzard and Jubilee in the UK North Sea and offshore Ghana, both stratigraphic fans which were not immediately obvious on seismic. “Downdip to the crest, these fan sediments thicken quite quickly. We know that the interval above the volcanics has a) black oil, b) plenty of pressure, and c) adequate reservoir properties for a very acceptable flow rate from wells. So in that one area, we have identified three different geological plays: on top, supra-volcanics, in the middle, sub-volcanics, and below that, basement. “This year, following award of the appraisal area, we will apply pre-stack depth migration to the existing 3D seismic to better image the fan channel system. Then we plan to drill a well to test as much as we can the fan structure to the north, and to confirm the interval above the volcanics, but in a more userfriendly environment – without the pressure gradients of the previous wells. “The structural setting on TGD indicates a potentially vast reservoir, but we need to prove continuity of the fan system. What we learn on TGD could also have a big impact on the TGT development.”

According to Maris, TGT’s reserves are large enough to warrant a standalone development, with a first phase likely based around a jacket platform on the northern part of the field, exporting its well stream to an FPSO. Another platform would be installed in a central part of the structure under a second phase with the option of potentially handling black oil from TGD. Ideally, the partners would like to get first production in 2010. Processing TGT’s Miocene and Oligocene crude should not present problems, he adds. Both are high quality, typically 43-45° API, and waxy, with a high paraffin content, making them ideal for use as aviation fuel. As for the gas from both fields, there is ullage available nearby in the Bach Ho trunkline to the Vietnamese mainland, where supplies are urgently needed for power generation and LNG/ LPG. In time the deeper-lying gas-condensate might be suitable for a proposed LNG scheme tying in various fields in the Cuu Long basin. Recently, PetroVietnam, recommended that the Vietnamese government also approve the Hoang Long JOC’s application for an appraisal area covering 100 sq km (39 sq mi) around the Voi Trang discovery and several nearby leads. The award is conditional on a successful reserves assessment report. 

Tired of operating on your BOP test unit BEFORE it will operate?

70-0....... A Winning Record

The first and only test unit with absolute redundancy.

Clover hydrostatic test units combine the most reliable features and components into a small footprint design. Our record speaks for itself. With over 70 units in the ¿eld, we’ve had zero failures over 7 years. Clover test units are easy to customize, maintain and operate anywhere on the rig. Our dual 20,000 psi. Model CTU-20PD2-4 triples your hydrostatic test capabilities. During critical operations, one side can be used as an immediate back-up. When operating in tandem as a single station, BOP ¿ll/test time is cut in half. Operating independently, integral twin recorders allow separate tests simultaneously at different psi. Clover Tool units are solid stainless steel, explosion proof and all electric for fast, reliable BOP, hose, valves, valve systems, manifolds and riser line hydrostatic testing.

𰁚𰁚𰁚𰀑𰁆𰁏𰁒𰁙𰁈𰁕𰁗𰁒𰁒𰁏𰀑𰁆𰁒𰁐𰀃𰃤𰀃𰀕𰀛𰀔𰀐𰀘𰀙𰀔𰀐𰀘𰀙𰀓𰀓 0902off_54 54

For less critical operations our economical 15,000 psi. single test unit Model CTU-15P-S1 is packed with features and has a long history of fast, flexible, flawless performance. Get complete details and specifications @www.clovertool.com

Aqua-Dyne

2/11/09 2:55:11 PM

0902off_55 55

2/11/09 2:55:13 PM

ASIA

Offshore Asia 2009 Focusing on offshore technology in an emerging deepwater region he 2009 Offshore Asia Conference & Exhibition will take place March 31-April 2, 2009 at the IMPACT Exhibition and Conference Center in Bangkok, Thailand. The Department of Mineral Fuels, Ministry of Energy, Thailand, has endorsed the conference, and PTT Exploration and Production Plc. (PTTEP) will be hosting. Dr. Kurujit Nakornthap, director-general of the Department of Mineral Fuels, and Anon Sirisaengtaksin, CEO of PTTEP, will address the conference at the official opening keynote session. “We are delighted Thailand will be hosting Offshore Asia 2009,” says Dr. Nakornthap. “The event will bring immense benefits to the regional offshore oil and gas industry and the country. Important subjects will be discussed during the three-day conference. We look forward to a successful and informative event.” “The enthusiasm and support of PTTEP and the Department of Mineral Fuels, Ministry of Energy, Thailand, will contribute immensely to the success of the event,” says John Royall, VP, Offshore group, PennWell Corp. “It is important that the region’s premier event for the offshore oil & gas industries continues to go from strength to strength and we are delighted that so many companies have already committed to exhibiting at Offshore Asia.” “Solutions for Asia’s Offshore Challenges” will be the theme of this year’s conference, now in its fourth year, which will focus on the specific technological needs of the Asia offshore arena. The conference program will cover a broad range of technical and topical issues - ranging from E&P to multiphase pumping - with a full schedule of tutorials and technical paper sessions. Offshore Asia is a key forum for engineers, engineering managers, senior executives, and industry leaders to discuss technology solutions, lessons learned and best practices to meet the challenges of offshore oil and gas exploration and production. The Offshore Asia exhibition covers all aspects of offshore technology and subsea applications. The exhibits will showcase the latest technology and foremost business ideas shaping the future of the industry. Suppliers, services companies, contractors, and service providers from the E&P, subsea, and multiphase pumping industries will showcase their new developments, technologies, and operating solutions at Offshore Asia 2009. Last year’s conference in Kuala Lumpur, Malaysia set attendance records, attracting 5,000 participants from 57 countries. More than 100 sponsors and exhibitors supported the event. This year’s event in Thailand is expected to attract over 5,000 industry professionals, who will gather for three days to experience the latest developments and innovations for the Asian offshore oil and gas sector. Energy business analysts Douglas-Westwood has predicted the emergence of Asia as a significant deepwater region that should not be overlooked. Indonesia, Malaysia, and India all have development prospects on screen for the 2009-2013 period and the region should account for nearly 10% of deepwater capex, they said. The event begins with an Opening Night Reception starting at 5 p.m. on Tuesday, March 31. Wednesday brings the Opening Plenary session at 9:30 am. Eldon Ball, conference director, PennWell, will give the Welcome and Introduc-

Why Thailand? Thailand has launched an international campaign to build long-term oil and gas reserves, given the strong 13% energy demand growth recorded since 1981. PTTEP is leading the way with its 2009 capex and opex budgeted at Bt50.05 billion ($1.6 billion) and Bt19.3 billion ($610 million).The company has built 38 projects in 14 countries, including 17 projects in Thailand. PTTEP has invested about $1 billion in the Arthit project in the Gulf of Thailand, which started producing on March 26, 2008.

The $500 million Arthit platform in the Gulf of Thailand produces 330 MMcf/d of natural gas and condensate and 10,000-13,000 b/d of oil, meeting about 10% of the domestic demand.

Chevron also continues to invest heavily in the region, and has signed a sales agreement with PTT to construct a second central natural gas processing facility in Platong. The $3.1 billion project is scheduled to start up in 1Q 2011, and will add 420 MMcf/d of processing capacity. Chevron’s cumulative investment in upstream activities in Thailand from 1962 to 2007 has been nearly $15 billion. About $4 billion in petroleum royalties was paid to the Royal Government of Thailand from 1981 to 2007, making a significant contribution to the nation’s economy.

tion followed by Dr. Nakornthap’s address, and Mr. Sirisaengtaksin’s Keynote Address. Tara Tiradnakorn, president of Chevron Thailand Exploration and Production Ltd., will present the Industry Perspective. There will be extensive coverage of E&P and subsea technology in the technical sessions this year, with topics including: • Construction and installation • Field development methods and technology • Drilling and well construction • Floating production systems • Subsea technology • New technology for ﬂowlines and pipelines The following summaries represent just some of the papers that will be presented at Offshore Asia this year.

56 Offshore February 2009 • www.offshore-mag.com

0902off_56 56

2/11/09 2:55:14 PM

ZPMC provides the following offshore products and services to customers worldwide.

World No. 1 7500T fully revolving floating crane, currently working in South China Sea

Various fully revolving or fixed jib floating cranes, with capacities ranging from 100T to 10000T, which are self propelled or non self propelled, equipped with DGPS or anchor winch system.

Jack up rigs under construction

Various jack up rigs, semi submerged rigs and fixed rigs. For the jack up rigs, the operating water depth is up to 500ft but drilling depth reaches 30000ft.

DLV4400 pipe laying barge under construction

Deep or shallow water pipe laying vessel equipped with a 2000T 5000T floating crane, using single or tandem node pipe laying, DP2/DP3 and 10 or 12 anchor winch system.

3500 cube twin bump cutter suction dredger under construction

Various dredging vessels, including cutter suction dredger, grab dredger and drag suction dredger.

LOOKING FOR MORE? ZPMC also supplies various specialized equipment for offshore work, including heavy duty winch (50 120mm wire rope diameter, up to 4000m in length), large case hardened reducer, large sized bevel gear, shallow or deep water pipe laying equipment (100m 3000m water depth), offshore painting, heavy duty brakes / couplings / sheaves / drums. Address: No.3470 South Pudong Road, 200125, Shanghai, Peopleâ&#x20AC;&#x2122;s Republic of China Phone: +86 21 5839 6666 Fax: +86 21 5839 9555 Website: www.zpmc.com Contact: Mr. Dai Wenkai daiwenkai@zpmc.com | Mr. Zhang Jian zhangjian@zpmc.com | Mr. Mo Jian mojian@zpmc.com

0902off_57 57

2/11/09 2:55:17 PM

ASIA

Tropical cyclone risk assessment for offshore platforms and rigs Dr. Polsak Tothong, AIR Worldwide Corp. Dr. Tothong will demonstrate a probabilistic risk assessment for physical damage and business interruption due to tropical wind, waves, and storm surge to offshore platforms and rigs. The methodology can quantify the current risk and the risk reduction with the application of mitigation measures, thereby providing a direct, optimal cost-beneﬁt evaluation-mitigation.

Parametric effect on pile drivability analysis in clayey subsoil Kaushik Mukherjee, J. Ray McDermott Asia Paciﬁc Focused on an independent study in the Gulf of Thailand, this discussion will be on the effect of variation in dynamic clay parameters on drivability analyses and choice of different pile make-up to suit it. The earlier experience and back-analyses of available records are also taken into account when reaching a conclusive judgment for the region.

The first dual lift jacket installation in Malaysia Vinodh Marimuthu, PETRONAS This discussion will cover the successful offshore installation of East Belumut 2,000-metric ton (2,205-ton) jacket by dual barge lifting due to the unavailability of the conventional single barge. Operator Newfield’s quick decision was to deploy an unusual method which is technically more challenging by using two below capacity barges. This presentation reveals Newfield’s experiences in efficiently managing the engineering, risk assessment and modifications within two months to ensure sound technical and reliable operations.

Technology advancement in mitigating inorganic scale – overview of scale challenges in Malaysian oilfields Noraliza Alwi, PETRONAS Research Sdn Bhd In this session, a review of selected Malaysian oil fields that are associated with scale problems in the near wellbore formation due to high water cut (30 - 90%) will be discussed. Several recommendations will be made on the basis of formation, injected water, and produced brine composition to inhibit scaling formation. Reservoir to wellhead pressure and temperature profiles were also taken into account while proposing the remediation techniques. This presentation will provide the comparison of the traditional treatment chemical and mechanical parameters.

Planning & following up well completion & workover activities using ontology of operations Dr. Carlos Damski, Genesis Petroleum Technologies The Deming’s PDCA Cycle (Plan, Do, Check and Act) aims to reach a continuous optimization in well completion and workover activities. A methodology based on Ontology of Operations has been implemented to aid this process of continuous improvement. In this presentation, more than 180 operations were identiﬁed and deﬁned based on ontology of operations. Dr. Damski will discuss the implemented methodology and proposes as a new step, the concept expanded to all well operations, including the drilling activities.

Improving well integrity management through computerized maintenance systems Richard Conway, Expro Well Services With the merger of companies and the sale/acquisition of oil ﬁelds, many operators now have assets spread across countries and even continents, with multiple management systems that can lead to problems, particularly in the management of well integrity. A demonstration of how com-

puterized maintenance systems can be used to improve the management of well integrity information will be given in this session, including delivery of critical data to relevant personnel regardless of geographic location.

Development of a powered, drill-thru casing reaming system Lance Davis, Futuretec Ltd. Adverse wellbore conditions often result in inefﬁcient and incomplete casing running operations, both in terms of costly non-productive time and potentially lost production. The presentation will describe how to improve casing running, integrating turbine technology with materials science to provide an evolutionary powered casing reaming shoe, which can be cemented in place and drilled through during the subsequent bit run.

Development and ﬁeld test of a new rotary steerable system Dr. Li Hanxing, CNOOC Research Center A new rotary steerable system (RSS) which uses a technique to enable precise, consistent, and predictable changes in well trajectory will be discussed. This tool incorporates a rotating drive shaft through the center of the tool and a non-rotating housing supported by large bearings. Field tests have been completed in Bohai Bay and Changqing oil ﬁeld and will be presented.

Shallow to deepwater applications the scope for the TCMS - riser and production mooring systems Douglas Davidson, Mooring Systems Ltd. The presentation will cover the commercial and practical beneﬁts of the Tri-Catenary Mooring System (TCMS), including a history and the latest innovations allowing the system to operate in water depths of up to 1,000 m (3,281 ft). The system allows for up to 10 risers/umbilical and can operate in seastates up to at least Hs=8.3 m (27.2 ft) depending on vessel size.

Field development floater Mats Rosengren, FDF Technology/DMC Offshore Pte The concept for a field development floater (FDF) to bring a confirmed hydrocarbon discovery offshore to production and to provide well intervention and workover services during the production phase will be discussed during this presentation. The FPF is an FPSO of a new design and concept for extended well test, early production, heavy crude production and marginal field production that would feature a crude oil process plant, crude oil storage capacity, and offloading facilities, among numerous other capabilities.

Rising to the challenge Dr. Tim Clarke, Optical Metrology Services Ltd. This talk will provide an insight into the world of risers, discussing their importance, where they are used, and how they are measured and welded before being put into the water.

The first gravity-based substructure (GBS) for the Caspian Sea Dr. Rodney Pinna, Arup Dr. Pinna will discuss the design of the first steel gravity-based structure (GBS) to be installed in Block 1 offshore Turkmenistan, located in the land locked Caspian Sea, including discussion of the drivers which lead to the selection of this design, and the final platform configuration. Block 1 is reached through the Volga Don canal system which is accessible only during the summer months, or via air and land transport. Another significant challenge faced in developing the reserves in Block 1 is the lack of availability of offshore installation equipment such as heavy-lift crane barges, pipelay barg-

58 Offshore February 2009 • www.offshore-mag.com

0902off_58 58

2/11/09 2:55:18 PM

0902off_59 59

2/11/09 2:55:22 PM

ASIA

es, and diving vessels. The design considerations for the ﬁrst self installing steel GBS to be installed in the Caspian will be covered.

try. A discussion on the initial technical challenges to provide substantial heating and chemical injection to ensure smooth and uninterrupted ﬂow from the wellhead platform to the FPSO will be presented.

Open systems architectures for subsea systems Kirstin Ballantyne, Aker Solutions This session will outline the development and deployment of a new open system architecture for subsea production/process control and demonstrate through project examples the power and ﬂexibility of this system, signiﬁcantly reducing project risk, and reducing the engineering effort and time to deliver. The application of open systems to conventional production control systems will be covered, along with subsea boosting and processing. It will also consider how these same techniques and components can be applied even to large scale integration on subsea gas compression systems.

Multi-ﬁdelity computational ﬂow assurance for design and development of subsea systems and equipment Dr. Demetris Clerides, CD-Adapco The status and future prospects of Multi-Fidelity Computational Flow Assurance will be discussed in this session.

OMV Maari FPSO: A template for specialized umbilical technology Gavin Rippe, JDR Umbilical Systems This session presents the unique technical solutions JDR developed to meet power /chemical umbilical speciﬁcations within the OMV Maari project offshore New Zealand. The Maari FPSO is designed to operate in one of the most environmentally demanding conditions within the indus-

Gas hydrates in subsea pipelines under gas-dominant flows: challenges, modeling, and large-scale experiments Affonso Lourenco, CSIRO Gas hydrates is a major flow assurance problem in offshore gas production worldwide and especially in Australia. This presentation will address the reasons why hydrates in gas-dominant flows are a different flow assurance challenge for the industry, and give solutions to avoid or mitigate the problem. It will investigate the effects of major variables under dynamic conditions such as pressure, temperature, water-cut, flow pattern, type, and concentration of condensates and inhibitors.

High performance pipe-in-pipe. Why push for it? Wayne Grobbelaar, ITP Interpipe Often flow assurance data is not precise, especially during the early stages of a project. An overview of why and how high performance pipe-in-pipe flowlines can benefit the operator during the life of field developments will be discussed, including analysis of costs and performance benefits. Project examples will be covered, illustrating the benefit of high performance thermally insulated flowlines with respect to installation, operational flexibility, life of field, and operational costs. Capital investment will also be discussed. Lunch sponsors during the show include AlMansoori Wireline Services (Thailand) Ltd. and Master Marine AS. For more information visit www.offshoreasiaevent.com. 

When your work is done,

Our work begins. THE INDUSTRY’S MOST COMPLETE PACKAGE OF DECOMMISSIONING SERVICES. After production winds down, decommissioning raises a whole new set of issues and risks. And Proserv Offshore handles them all for you – expertly, safely and responsibly. The leader in offshore oil and gas facility decommissioning, we have more than two decades of planning and execution experience, ensuring that every project is efficient, cost-effective and safety-oriented from start to finish.

Decommissioning Contractors & Engineers

We handle every aspect of offshore oil and gas platform and subsea decommissioning for majors, independents and national oil companies around the world. So when your work is done, you can relax. Because we’ll take it from there.

0902off_60 60

2/11/09 2:55:24 PM

Extreme Depths Extreme Lift

XLift

HIGH-PRESSURE GAS LIFT SYSTEM

Improve your production in deep water. Deepwater and subsea applications require proven technology that delivers deeper injection points, higher injection rates, and higher injection pressures while maintaining pressure integrity between the tubing and the annulus: Q

5,000-psi injection pressure rating

13.5-MMcf/d injection rates

positive sealing check valve.

Increased pressure and injection rates enable maximum drawdown and improved recovery with fewer valves and mandrels, set deeper in the well. Achieve production metrics. Using the XLift* high-pressure gas lift system, a Norwegian Sea operator is maintaining continuous and reliable performance and achieving an average injection rate of 9.4 MMcf/d at an average surface injection pressure of 3,125 psi to produce 5 subsea oil wells. www.slb.com/xlift

Global Expertise | Innovative Technology | Measurable Impact

0902off_61 61

2/11/09 2:55:27 PM

ASIA

Intensive five-year drilling campaign to lift production from Bohai Bay fields Program taps new reserves in Zhao Dong block OC Oil is strengthening its position as the fourth-ranked foreign operator of oil production in China. The Sydney-based company, active in the country since 2002, is midway through a program to expand and to extend production from the Zhao Dong fields in Bohai Bay. It also is close to initiating a brand new cluster development 2,500 km (1,553 mi) to the southwest in the Beibu Gulf. The Zhao Dong block extends over 27.5 sq km (10.6 sq mi) in shallow water, close to the shore in Bohai Bay, southeast of Beijing. No previous drilling had occurred in the permit before 1993, when XCL was awarded the PSC for a seven-year exploration and development period, followed by a 15-year production term. After an initial discovery made by XCL, Apache farmed into the acreage and assumed operatorship in 1994, increasing its equity in the block in 1995. Seven subsequent appraisal wells also encountered significant quantities of oil. First production was in 2003. The Zhao Dong fields comprise stacked reservoirs ranging from Permian age clastics to the late-Tertiary Minghuazhen formation. Of the different stratigraphic levels, 27 are known to contain oil, and 16 of these were developed between 2003-07, via 31 production wells and 20 water injectors. According to ROC, the source rock is rich and generative, and oil typically is found wherever a prospective trap exists. There also are small quantities of associated gas, which is used currently for power generation. Excess volume is flared. Reservoir quality in the productive zones generally is high. Some of the deeper targets are tighter, but also tend to have higher API crude, with better flow characteristics. The block is part of a prolific oil-producing province: nearest fields in production are Caofendian 13-1 and the Qikou complex (both offshore), and the Dagang fields onshore. ROC acquired Apache’s equity in 2006, in the process becoming operator with a 50% exploration interest; a 24.5% development interest (including the C and D fields); and

Jeremy Beckman

Editor, Europe

an 11.575% unitized interest in the C4 ﬁeld, which is part of the current second-phase program. Partners in the development are PetroChina and New XCL-China LLC, with the latter also holding the remaining 50% exploration interest.

Facilities review Zhao Dong C and D were developed initially via two bridge-linked platforms in 3-5 m (9.8–16.4 ft) water depth, 10 km (6.2 mi) from the shoreline. One platform serves for drilling and accommodation, the other for processing and storage. Crude is ofﬂoaded onto a barge for transportation to the nearby port of Tangu, and subsequent loading onto tankers for export. The oil is waxy, with a low sulfur content, and gravity ranges from 18º-38º API, but typically 20º API. When ROC took over from Apache in 2006, 20 MMbbl had been recovered, but production was set to decline. The partners conducted further geological and reservoir

modeling studies as part of a program to extend field life. The review suggested that a further 27 MMbbl could be extracted via a program of: • New wells and re-completions in the C and D fields • Extended reach wells into a previously undeveloped section in the north-eastern part of the C structure • A new drill center accessing reserves from the C4 field straddling the boundary with the adjacent Eastern block. The JV partners have a current budget around $426 million for an Incremental Development Plan (IDP), which includes construction of a second drilling platform (ODB) and a fluids processing and storage platform (OPB), both to be stationed next to the existing production facilities. Around 110 new wells or re-completions are planned throughout the Zhao Dong and C4 fields between 2007 and 2011. A drilling conductor pod (CP2) and a pipeline terminal also were commissioned, both north of the Zhao Dong facilities on a stretch known as the Extended Reach Area, and connected to the main production facilities by 4.5 km (2.8 mi) long oil and water injection pipelines. According to ROC, “there has Schematic shows location of the new drilling and processing facilities on the Zhao Dong fields.

62 Offshore February 2009 • www.offshore-mag.com

0902off_62 62

2/11/09 2:55:29 PM

L I Q U I D

L E V E L

Ever notice how some

M E A S U R E M E N T

technologies shrink as they get smarter?

SFF 92.3% SIL 2

The all-new E3 Modulevel ®

Smaller. Smarter. ntroducing the E3 Modulevel, our fourth generation displacer transmitter featuring the most advanced software

and functional capabilities to date. Now housed in a distinctive dual compartment enclosure with an integral LCD, the all-new, digital E3 delivers better performance and uses today’s most advanced software. The E3 is HART® and PACTware™ capable.

The E3 is smaller and less bulky, too, weighing in at 25 pounds less than earlier Modulevel transmitters. To learn more about today’s leading-edge in displacer-based, continuous level or interface monitoring, visit magnetrol.com

1-800-624-8765 • magnetrol.com info@magnetrol.com

0902off_63 63

E3 MODULEVEL

Worldwide Level and Flow Solutions

2/11/09 2:55:31 PM

L I Q U I D

L E V E L

Ever notice how some

M E A S U R E M E N T

technologies shrink as they get smarter?

SFF 92.3% SIL 2

The all-new E3 Modulevel ®

Smaller. Smarter. ntroducing the E3 Modulevel, our fourth generation displacer transmitter featuring the most advanced software

Worldwide Level and Flow Solutions

1-800-624-8765 • magnetrol.com info@magnetrol.com

0902off_63 63

2/11/09 2:55:31 PM

ASIA

Sticking to the schedule was a major achievement given the pressures on the Chinese construction industry arising from the Olympics and natural disasters. always been a program of water injection/ pressure support on Zhao Dong. As more wells are drilled and reservoirs developed, more water will be produced and re-injected.” Both the pod/pipelines and the ODB platform entered service late last year, with seven associated development wells on stream by November. This helped lift average production from Zhao Dong to over 30,000 b/d, compared with just over 16,000 b/d when the program started. Sticking to the schedule was a major achievement, according to Bruce Clement, ROC’s CEO, given the pressures on the Chinese construction industry arising from the Olympics and natural disasters. The resultant power cuts, logistics, and transportation restrictions all impacted progress on the project. The ﬁnal four wells in the 2008 campaign – three on ERA and one on C4 – were completed and online in December. Development drilling then was suspended for the winter, but should resume shortly. The OPB is expected to be installed and commissioned some time this spring. Design, fabrication, and installation has been handled by a mix of Chinese and foreign engineering contractors. Despite the increase in production, the underlying natural decline at Zhao Dong will continue. The partners will address that issue with a further program of development, which should start after the current program is completed in 2011.

Beibu production issues In Beibu Gulf Block 22/12, covering an area of 342 sq km (132 sq mi), ROC Oil is op-

The newly on stream Zhao Dong ODB platform with drilling rig alongside.

erator with 40%, in partnership with Horizon Oil (30%), Petsec Petroleum (25%), and Oil Australia (5%). ROC farmed into the block in 2002. Within a month, the first exploration well was drilled, discovering the small Wei 6-12 oil field. Over the next six years there were further successes on Wei 6-12 South-1 – a potentially significant oil find – which intersected 95 m (311 ft) of net hydrocarbon pay. Testing three separate zones led to a collective, stabilized flow rate of 5,750 b/d. A sidetrack well encountered similar reservoir quality, while a second sidetrack, designed to test reservoir intervals in the upper part of the original discovery well, intersected 16 m (52 ft) of net oil pay across four reservoir sands. ROC drilled four more exploratory wells, one of which, on Wei 12-8 East, found viscous oil. Early last year, ROC drilled two further prospects on the 6-12W structure, but neither found commercial hydrocarbons. In the south of the block are two undeveloped oilfields discovered by the previous regime – Wei 12-2, Wei 12-3, and one oil and gas accumulation, Wei 12-8 West. The block again is situated in a prolific oil province, the nearest producing field being Wei 12-1 just to the north of Wei 12-2, which draws oil from the Weizhou formation. Reservoirs in this region range from Eocene-age fluvial-lacustrine sandstones from the Luishagang formation, to Miocene

Jiaowei shallow marine sandstones and Oligocene Weizhou sandstones. Oil quality varies from light to heavy, with generally low to medium viscosity, and some waxy crudes. Progress with development has been slower than ROC anticipated following this early program of work, but last September CNOOC confirmed that the Wei 6-12, Wei 6-12 South, Wei 12-8 West, and Wei 12-8 East fields had been declared development areas. Currently, the partners are working on an overall plan for the first three of these fields, which have combined recoverable oil reserves estimated at 27 MMbbl. The fourth, Wei 12-8 East, will likely be developed under a second phase. The most likely scenario involves a wellhead platform on Wei 12-8 West and a combined wellhead and process platform at Wei 6-12 with oil exported via tieins to a new CNOOC pipeline to the latter’s Weizhou Island Terminal. Before agreement on a proposed scheme can be reached with CNOOC, further studies are needed to optimize the project’s economics, to satisfy both the foreign joint venture participants and CNOOC. Once these studies are completed, an overall development plan will be submitted to the Chinese government. ROC is hopeful of gaining CNOOC’s approval by end-April. In this case, the government has a back-in entitlement to take up to 51% equity in the development. 

64 Offshore February 2009 • www.offshore-mag.com

0902off_64 64

2/11/09 2:55:32 PM

0902off_65 65

2/11/09 2:55:35 PM

GEOLOGY & GEOPHYSICS

BPC re-assessing potential of southern Bahamas play Jeremy Beckman

Editor, Europe

he revival of exploration off northern Cuba has rekindled interest in the Bahamas. Although no wells have been drilled off the islands since 1986, new geological studies suggest strong analogies among producing provinces from Cuba and southern Florida to giant fields such as Cantarell in the southern Gulf of Mexico. Spearheading the review is BPC, formed in 2005 by Alan Burns, who also pioneered deepwater exploration off Mauritania with his previous company, Hardman Resources. BPC is the only company active offshore the Bahamas, operating four contiguous licenses on the median line with northeast Cuba, and the Miami license between Grand Bahama Island and the Florida coast. The combined acreage covers an area of 15,676 sq km (6,053 sq mi). Over the past three years BPC has compiled a detailed inventory of the islands’ exploration history based on all available data, including 7,000 km (4,350 mi) of seismic lines, well cores, and rock samples dating back to the 1950s. Using contemporary imaging techniques, it has identified 22 leads in its five offshore licenses, with potential for large traps containing structures of up to 500 MMboe. The company has an office in the Bahamian capital, Nassau, with two full-time staff and a legal team on retainer. “As a very small, start-up operation,” says COO Paul Crevello, “we had to demonstrate to the government our ability to perform both technically and financially before securing our licenses.” Crevello, a geologist recruited by Burns in 2006, is based in Boulder, Colorado. His area of expertise is carbonate reef systems, notably the structural setting formed in and around the Bahamas that he began investigating as a student at the University of Miami in the 1970s. This play was also the focus of major oil companies including Gulf Oil, Shell, and Standard Oil during the islands’ first post-war exploration phase. All were looking for the same type of carbonate reservoirs that had been proven onshore in the Middle East. In 1978, Crevello joined Marathon, which at the time had interests in large carbonate fields such as Yeats onshore Texas and others in the UAE and Libya. Crevello directed the company’s global carbonate geological exploration research, also running a carbonates training program which included organizing field trips to the Bahamas, Belize, and southern Florida for coral reef studies. When the research facility in Denver closed in 1994, Crevello moved to the Far East to start another training program at the University of Brunei, funded by Shell, and later his own consultancy, Petrex Asia, in Kuala Lumpur.

Drilling history Previous exploration around the Bahamas occurred in phases between 1946 and 1987, all in shallow water. The first well, drilled in 1947 on Andros Island to a subsurface depth of 14,583 ft (4,445 m), was abandoned with no significant well shows. From 1948-55, Gulf Oil led the way, conducting the first experimental underwater seismic and gravity surveys in this area. During this period, Gulf also

BPC’s licenses offshore the Bahamas, including prospects.

drilled the 826-Y well off Key West, Florida – the sole oil discovery to date in the region – which flowed 18 bbl of 22-24º API crude from an anhydrite/carbonate interval below 10,000 ft (3,048 m). In 1958, Zapata, owned by Howard Hughes and George Bush Sr, undertook an ambitious program (at the time) which led to drilling of Cay Sal No.1, offshore north-central Cuba. This location was drilled jointly by Chevron and Gulf a year later, the well encountering “live” oil shows from 12,682 ft (3,865 m) downwards. From 1959-68, these two companies continued to drive exploratory activity, conducting various unproductive marine seismic programs which included the use of dynamite as an energy source. In 1970 they joined forces with Mobil to drill the Long Island and Great Isaac Bank wells: the latter, in BPC’s Miami license, flowed gas and condensate to the surface from the 16,900-17,700 ft (5,151-5,395 m) interval. Over the following decade, the focus switched to digitally based seismic, gravity, and magnetic surveys. Further seismic and core samples also were acquired as part of a scientific project to analyze the Bahamian carbonate bank. Thereafter, various oil companies commissioned seismic, geotechnical, and geochemical studies. The final well was drilled by Tenneco in 1986 on the Doubloon

66 Offshore February 2009 • www.offshore-mag.com

0902off_66 66

2/11/09 3:28:17 PM

NOW EVEN THE HIGH SEAS HAVE AN HOV LANE. The Bell 412. It offers more cabin space than any other medium twin and the lowest seat-mile cost in class. Plus durability to get you and your crew out and back safely, clear skies or gray. n it iitss cl clas ass. as s. P s. luss th lu the e du ura ab Welcome evolution Series. Welcome leading edge vertical lift. W We lcom lc ome om e to tthe he ee vo olu luti tion ti o o on off th the e 4 Se S ries. We Welc lcom om me to tthe he le eading ng e dg d ge of v erti er tica ti c l li ca lift ftt.™

0902off_67 67

bellhelicopter.com b be l 1-800-FLY-BELL

2/11/09 3:28:24 PM

GEOLOGY & GEOPHYSICS

Map shows drilling locations for BPC’s well and core data base.

Saxon structure in BPC’s Donaldson license. This was also the deepest well drilled to date, at 21,470 ft (6,544 m) TD, encountering live oil shows over a thick interval. Postdrilling, both Tenneco and Shell acquired more experimental surveys, but they and the remaining operators quit in 1988 when the licenses expired, due to a combination of high costs and low oil prices. More recently, Kerr-McGee and Liberty Oil & Reﬁning applied for exploration licenses north of Grand Bahama Island. Western Geco acquired speculative seismic in this area, well away from BPC’s licenses, but otherwise activity around the Bahamas ground to a halt.

Cuba parallels BPC began its quest for all the available geological and well data in 2005, purchasing materials from oil companies, universities and research institutes. These included storage facilities in northern Britain, and cores stacked on shelves at a university warehouse in Louisiana. “We took paper copies of all existing data sheets, digitized them, and put them in our workstations,” Crevello explains. The subsequent review using modern interpretive techniques found that most of the wells drilled around the Bahamas were either in the wrong locations or were hampered by poor quality seismic or imaging constraints. “Both the Long Island and Great Isaac wells were drilled blindly,” Crevello suggests, “while Gulf in 1960 found a stratigraphic trap off Key West that produced 15 bbl of 22-24º API oil on test, but could not delineate the oil column. And in those days the drilling technology was not available to test the potentially larger structures held by Tenneco out at 500 m (152 m) water depth.” However, based on analysis of oil shows of varying quality, widespread reservoirs and seals, and hydrocarbon saturations from log interpretation – particularly in pre-Cretaceous unconformity sections – BPC believes active petroleum systems could be present. “We also drew on literature on source rocks in Cuba published by institutes in Spain and France,” Crevello adds, “which revealed shales with a high organic material content – up to 14%. We feel the same rocks could be present in the sub-surface in our southern licenses. “This area is just north of the productive

North Cuba field and thrust belt, which was created when the Caribbean plate collided with the southern margin of the North Atlantic plate. The same age source rocks extend farther west along a compressed fault belt into the southern Gulf of Mexico: the analogues are mainly with the multi-billion barrel fields such as Canterell and Golden Lane/Poza Rica in the Mexican sector, rather than the smaller deepwater fields on the US side which are located on a passive, subsiding margin. “One problem with the northwest Cuba area is that it lacks a good seal, possibly due to its paleogeographic position during the early Cretaceous. But we are dealing here with big carbonate platform reservoirs and evaporate sealing beds. Carbonate reservoirs provide the main source of Cuba’s prospective resources, which the US Geological Survey estimates at 18 Bbbl recoverable, while the Cuban Petroleum Company puts reserves at more than 20 Bbbl.”

Negotiations In recent years, the Bahamas has stayed off the industry’s radar, Crevello believes, because it is too close to the US for groups working in the Caribbean, where the focus has been on Trinidad and Venezuela. Lack of serviceable well data has been another issue, as was the previously unfavorable Bahamian tax regime. Now, however, the exploration terms are more generous, with licenses renewable every three years for a period of up to 12 years. BPC is pursuing multiple farm-outs in its various licenses to fund the next phases of exploration. “We’ve been talking to majors,” Crevello

says, “and they see upside potential for huge fields on our acreage. Although today’s economic environment is weaker, we will continue to search aggressively for suitable partners. “Our initial focus will be on seismic acquisition in deeper water, where we have identified numerous structures, and on establishing petrophysical parameters. We will also look at commissioning a satellite-based hydrocarbon seep study. Then, using our old data, we will gear up for organic-geochemical studies for source potential analysis, followed by additional petrographic calibration of well logs. This program could take 18 months to complete. “If negotiations with farm-ins go well, we would contemplate starting seismic acquisition later this year – in this region, the best time would actually be the hurricane season, as that’s when the weather is most stable versus winter, when many fronts pass through the area.” As for drilling, which could get under way in 2012, BPC would expect its share of costs to be borne by the farm-in operator. Any commercial discoveries would likely be developed via a floating production system (in deeper water) or a jack-up platform. Nearby export infrastructure includes a 20 MMbbl oil storage terminal at Freeport, owned by PDVSA. In the event of a major gas find, the export options could be a low-cost compressed natural gas tanker, offloading perhaps to the proposed Port Dolphin submerged LNG reception terminal offshore Florida; or a pipeline taking the gas subsea either to Fort Lauderdale (from fields in the Miami license) or to Freeport. 

68 Offshore February 2009 • www.offshore-mag.com

0902off_68 68

2/11/09 3:28:26 PM

LIQUID LEVEL MEASUREMENT

When the going gets tough, the tough get an Orion. Orion level gauges take on the toughest measurement challenges in the world’s harshest conditions.

rion level controls are built tough. Our Aurora Magnetic Level Indicator (MLI) combines float-

operated and leading-edge electronic measurement in a single, redundant indicator. Orion MLIs not only serve industry’s most demanding applications and environments, they’re built to thrive in these extremes. Learn more about new or replacement solutions in

AURORA®

Float-based level indicator with a redundant Guided Wave Radar transmitter

ATLAS™

Float-based Magnetic Level Indicator (MLI)

JUPITER® Float-based Magnetostrictive level transmitter shown mounted to an Atlas MLI

liquid level indication at orioninstruments.com. • Onshore/Offshore Oil & Gas

• Oil and Gas Refining

• Thermal & Nuclear Power

• Water & Wastewater

• Pharmaceutical & Biotech

• Chemical Processing

6646 Complex Drive • Baton Rouge, LA 70809 • 1-866-556-7466 • info@orioninstruments.com

0902off_69 69

2/11/09 3:28:28 PM

GEOLOGY & GEOPHYSICS

Life-of-field seismic system adds value to reservoir simulation of Valhall field System provides valuable raw data to predict responses he frequent time-lapse observations from the Life of Field Seismic (LoFS) system across the Valhall field have provided a wealth of information. The production and injection responses can be observed through time-shift and amplitude changes. These observations can be compared to modeled synthetic seismic responses from a reservoir simulation model of the Valhall Field. The observed differences are used to update and improve the model with a better match to the historical data. The uncertainty of the resulting model is reduced and a more confident prediction of future reservoir performance is provided. Workflows are used to convert modeled properties to a synthetic seismic response for any time range. Correlation-based match quality factor are calculated to quantify the visual differences. This match quality factor allows us to quantitatively compare multiple LoFS time ranges, well areas, and alternative models to help identify the parameters that best match the seismic observations. Three different case studies are shown where this method has helped to reduce the uncertainty range associated with specific reservoir parameters. By updating various reservoir model parameters we have been able to improve the match to the observations and thereby improve the overall reservoir model predictability. The examples show positive results in a range of different situations, which indicates the flexibility of this workflow and the ability to have impact in most reservoir modeling problems. Valhall field is in the southern North Sea and has been on production since 1982. More than 700 MMboe was produced during its first 25 years of production. Approximately 50% of the drive mechanism has been from rock compaction. A water injection program was initiated in 2004 to optimize recovery and to extend field life by 40 or more years. To help monitor production and water injection performance, a full field, permanent LoF system was installed in 2003. The fourcomponent, ocean-bottom seismic array consists of 13 cables with a total of 2,414 receivers and covers an area of approximately 45 sq km (17 sq mi). As of this report, eleven

J. van Gestel K.D. Best O.I. Barkved J.H. Kommedal

BP Norway

time-lapse surveys have been acquired: November 2003, April 2004, June 2004, November 2004, April 2005, November 2005, June 2006, April 2007, November 2007, April 2008, and November 2008. Additional surveys are planned twice each year. The LoFS observations are used in various parts of the Valhall subsurface organization. The Well Delivery Team uses these time-lapse observations to select the well targets and to better deﬁne the landing location for future wells. The Base Management Team reviews the LoF observations to plan well interventions and to monitor well performance. The Reservoir Management Team uses the data to improve the predictive capabilities of the reservoir model using history matching. This updated model then is used to better monitor the waterﬂood, to recognize areas that are not optimally swept, and to update area depletion strategies. LoFS also is used to monitor microseismic-

ity and well failures, and to improve the geomechanics model.

RTM modeling LoFS observations are integrated with the reservoir model using the workflow as shown. Synthetic seismic data are generated for multiple reservoir models using Valhall specific rock physics and seismic forward modeling software. The synthetic seismic data are processed using the same automated time-lapse analysis workflow as the recorded seismic data. These result in two identically derived amplitude difference extractions. In the same manner, compaction maps are generated from the reservoir model to match with observed time-shift maps. Matching reservoir compaction to time-shift due to induced changes in the rock outside the reservoir requires dedicated modeling of the stress-redistributions by coupling the reservoir simulator model with the geomechanical model. However, a simplified first order match may be established using a linear relationship with an estimated R-factor. Using observations from the actual extractions and modeling using mech2seis software the R-factor of 5.7 was found to be relevant in these cases.

Reservior model

Seismic data

Seismic modeling software

Processing

Synthetic seismic volumes Time-lapse analysis

Seismic volumes Calculation from initial thickness, initial porosity and pore volume multipliers

Time-lapse analysis

Difference volumes

Time shift volumes

Extraction

Map with observed seismic changes

Map with observed time shifts

Map with predicted seismic changes

Match quality factor

Equation using R=5.7 Map with predicted compaction maps

Match quality factor

Map with observed compaction

The workflow for integration of LoFS data with the reservoir model. The input is in blue, modules are in green, products are in yellow, the final output is in orange. This workflow can easily be repeated for different time ranges, areas of interest, and reservoir models.

70 Offshore February 2009 • www.offshore-mag.com

0902off_70 70

2/11/09 3:28:29 PM

GEOLOGY & GEOPHYSICS

The synthetic seismic data and the compaction maps are loaded into the seismic interpretation package. Images of the most important observations are generated automatically. These images can be accessed via the Web to allow for quick comparison of the observed and predicted responses. The most important extractions are compared visually. Differences are noted and the reservoir model with the best match is identified. Since the visual inspections are time-consuming and subjective, calculation of a Match Quality Factor (MQF) is included in the automated workflow. This MQF is based on a correlation of the two maps and is similar to the Seismic Match Quality of Kjelstadli, et al. (2005). The MQF is a number between 0% (no match at all) and 100% (identical data equal perfect match). Comparison of the MQF to the visual inspection in various areas for different extractions has built confidence that the MQF is a good measure of the match between two maps, especially on a relative scale when comparing two similar reservoir models. An automated workflow similar to the one described by van Gestel, et al. (2007) generates several MQFs for the different LoFS time ranges, extractions, and areas of interest. This allows quick comparison of a range of reservoir models in different situations. It also improves the confidence in an observation when it is supported by similar results in various parts of the field and different LoFS time ranges. Furthermore, automation of the workflow allows for linkage with a Top Down Reservoir Modeling workflow. In that workflow, the observations are compared to a large number of reservoir models generated from a large range of parameters. The MQFs are used to automatically improve the match to the observations to decrease the parameter uncertainty space.

Comparison between the compaction of reservoir model 5 (3A) and the recorded compaction response (3B). In both figures the LoFS 6 minus LoFS 1 response is shown. 3C shows the Quality Match Factors for the compaction response for three different time ranges. In all cases reservoir model 5 has the best match.

Comparison between the worst match from model 17 (2A) and the best match from model 35 (2B) predicted reservoir model responses that can be compared to the recorded observation (2C). In all figures the LoFS 6 minus LoFS 1 amplitude difference response is shown.

Case studies This workflow is powerful when changing one key parameter and quickly observing the effect of that parameter on the resulting time-lapse responses. The following three case studies are shown with a problem description, some observations, and conclusions. 1. Confined sub-basin: The first case is a detailed sub-basin study. The advantage of this sub-basin is that it contains a limited number of wells -- one producer and one converted water injector -- which makes it easy to study the responses of each well. The water injector was converted into a water injector in May 2005 and has shown a good time-lapse amplitude response in the following LoFS Survey 6 in November 2005. For this basin, a range of 40 different

Comparison between the original (4A) and the updated (4B) predicted reservoir model responses that can be compared to the recorded observation (4C). In all figures the LoFS 7 minus LoFS 1 amplitude difference response is shown.

reservoir models were generated with variance in several model properties such as vertical permeability, fault transmissibility, and pore volume multipliers. The 10 models with the best match to the reservoir parameters of pressure, GOR, and water cut then were compared to the observations for the sixth and seventh LoFS surveys. Both amplitude and time shift difference maps were compared. The amplitude difference maps show the most conﬁdent signal and provide the best measure of match of the various

models. The lessons learned from the best matched models are ported back to the full ﬁeld model. Work is ongoing to improve the match. 2. Changing gas-oil relative permeability curves: The second case study is a ﬁeld wide study of the effect of changing the gas-oil relative permeability curves. Several reservoir models were generated with only the gas-oil relative permeability curve changed. The effect of this change was examined in two sub-basins for various wells www.offshore-mag.com • February 2009 Offshore 71

0902off_71 71

2/11/09 3:28:29 PM

GEOLOGY & GEOPHYSICS

and for different LoFS time ranges. The gas-oil relative permeability has a large effect on how fast the pressure declines away from the wellbore and therefore has a strong side effect on the resulting compaction. This calculated compaction can be compared to the observed compaction, which is calculated from the observed timeshifts. A range of models were generated and both the effect where the compaction was too confined to the wellbore and also the effect where it was too widely spread were captured in those models. The reservoir model with the highest MQF was between the extremes. This was used in combination with other data sources to select the new gas-oil relative permeability curves for the full field reservoir model. 3. Flank improvement: The third study focuses on several of the wells on one flank of the field where mismatches between the location and direction of time-lapse effects due to production where obvious. By changing the skin of the well, local thickness variations, and the contribution of the various perforations along these horizontal wells, better matches between the observed responses and the predicted responses from the reservoir model were achieved. A wide range of MQFs was calculated for different wells and

different time-lapse windows to compare the original model with the updated one. The final reservoir model improves the match between the observations and the modeled responses. These modifications were ported back to the full field model. 

Acknowledgements

We thank BP and the Valhall partnership (BP Norge AS, Amerada Hess Norge, Total E&P Norge AS, and AS Norske Shell) for permission to publish this paper. We thank our colleagues who helped with this abstract: O.J. Askim, Katherine Hyland, Daniel Johnsen, Ra’ed Kawar, Roar Kjelstadli, Einar Kjos, Tron Kristiansen, Scott Lane, Terje Litlehamar, Ruth Synnøve Pettersen, Gunnar Tjetland, and Giles Watts.

Editor’s note: This paper was presented at EAGE. References Askim, O. J. [2003] Seismic forward modeling in a chalk reservoir with permanent monitoring, 65th EAGE Conference and Exhibition, Expanded Abstracts Barkved, O. I., Barkved, O. I., Kommedal, J. H., Kristiansen, T. G., Buer, K., Kjelstadli, R. M, Haller, N., Ackers, M., Sund, G. and Bakke, R. [2005] Integrating Continuous 4D Seismic Data Into Subsurface Workﬂows 67th EAGE Conference and Exhibition, Expanded Abstracts

Barkved, O. I., Bærheim, A. G., Howe, D. J. , Kommedal, J. H. and Nicol, G. [2003] Life of Field Seismic Implementation – “First at Valhall” 65th EAGE Conference and Exhibition, Expanded Abstracts Hatchell, P. J., Kawar, R. S. and Saviski A. A. [2005] Integrating 4D seismic, Geomechanics, and reservoir simulation in the Valhall oil field, 67th EAGE Conference and Exhibition, Expanded Abstracts Kjelstadli, R. M., Lane, H. S., Johnson, D. T., Barkved, O. I., Buer, K. and Kristiansen, T. G. [2005] Quantitative history match of 4D seismic response and production data in the Valhall field, Offshore Europe 2005, SPE 96317 Kommedal, J. H., Barkved, O. I. and Henneberg, K. [2005] Repeatability using a permanently installed seismic array, 65th EAGE Conference and Exhibition, Expanded Abstracts Kristiansen; T. G., Barkved, O. I., Buer, K. and Bakke, R. [2005] Production Induced Deformations Outside the Reservoir and Their Impact on 4D Seismic, IPTC 10818 Lane, H. S., Kjelstadli, R. M., Barkved, O. I., Johnson, D. T., Askim, O. J. and van Gestel, J. [2006] Constraining Uncertainty with frequent 4D seismic data at Valhall field, Offshore Technology Conference, OTC18222 van Gestel, J., Barkved, O. I. and Kommedal, J. H. [2007] Valhall Life of Field Seismic Automated Workflow, 77th SEG Annual Meeting, Expanded Abstracts

MAPSearch MAPS A PennWell Company

MAPSearch is the most trusted and utilized provider of GIS data to the petroleum industry for your M&A and asset valuation analysis. We provide detailed pipeline and pipeline facility information for use in Merger and Acquisition Analysis such as: • What pipeline assets does Company “A” now own? • What gathering, processing, and storage facilities do they operate? • If we were to acquire these midstream assets: – Wha What would their combined assets look like? – What new ew markets could they reach? MAPSearch Sea m trackss midstream pipelines and pipeline facilities for all of North America and provides this information formation n in a mappable format for users to conduct their own analysis.

For more information form please ase revi review our product offerings at www.mapsearch.com ch o tac us directly at 800-823-6277. or contact

0902off_72 72

2/11/09 3:28:31 PM

đ° ´ Incorporating Subsea Technology Asia đ° ´

31 March - 2 April 2009 IMPACT Exhibition & Conference Centre, Bangkok, Thailand www.offshoreasiaevent.com

WHY ATTEND OFFSHORE ASIA 2009 ! $ # $ & % & #

& !

FOR EVENT INFORMATION AND REGISTRATION VISIT: WWW.OFFSHOREASIAEVENT.COM Hosted by:

Endorsed by:

PTT Exploration and Production Public Company Limited (PTTEP)

Owned & Produced by:

0902off_73 73

Department of Mineral Fuels, Ministry of Energy, Thailand

Flagship Media Sponsors:

Incorporating:

2/11/09 3:28:33 PM

DRILLING & COMPLETION

Project offshore Qatar extends horizontal drilling limits Development optimized with multi-lateral wells aersk Oil Qatar is operator of Al Shaheen ﬁeld on the central axis of the Qatar Arch some 70 km (43.5 mi) northeast of the Qatar peninsula. The main production targets are the Lower Cretaceous Kharaib B and Shuaiba carbonate formations and the Nahr Umr sandstone. The ﬁeld is being developed with long horizontal wells because of the following: • The large areal extent of the accumulation • Poor vertical well productivity • Number of platform locations required for a conventional approach. The Al Shaheen development is ongoing from nine platforms, which was made possible only by drilling extended reach wells. The length of these horizontal wells has been extended during development, and some of these wells push the limit of what can be achieved with today’s technology. Implementation of multi-lateral wells has the potential to further optimize the development by reducing the number of required drilling slots, saving on top-hole costs, and reducing operational expenditure due to the decreased number of wells. All this can be achieved while maintaining the very long horizontal sections already employed in the single lateral wells.

Multi-lateral well philosophy The initial motivations to drill multilateral wells were twofold. First, there are a large number of wells being drilled as part of the current ﬁeld development plan (FDP). As the development progresses, more opportunities are being identiﬁed to optimize recovery by drilling wells. It was foreseen that these additional wells and wells planned for future phases of the FDP could result in platform slot constraints at some locations. Second, drilling rig day rates have increased to

Al Shaheen field, offshore Qatar.

David Brink Barry Gabourie Morten Hesselager Pedersen

Maersk Oil Qatar AS

M. Rushdan Jaafar

Qatar Petroleum

unprecedented levels, which makes the cost of drilling tophole sections significant. This increases the potential cost savings from reducing time spent tophole drilling and also benefits by accelerating production. As planning progressed, it also became apparent that multi-lateral wells could optimize the development of some sections of the field due to benefits associated with well pattern positioning.

Junction selection After reviewing various multi-lateral options, it was concluded that Technical Ad-

vancement of Multi-laterals (TAML) Level 2 junctions were optimum for this development. These junctions are simple and relatively risk-free compared to higher level multi-lateral junctions, provided the cement quality of the motherbore casing is good. There is no mechanical or hydraulic integrity at TAML Level 2 junctions. However, this is not required for these applications. Multi-lateral wells of this design have been used extensively in the Middle East with few failures. Furthermore, service providers in the region are geared for this type of installation.

Well construction The two TAML Level 2 multi-lateral wells drilled to date in the Al Shaheen development have 20-in. (51-cm) conductor, 13-3/8 in. (34-cm) surface casing installed down to the Laffan formation, and 9 5/8-in. (24-cm) production casing with the shoe set in the reservoir section accessed by the well. A tangent section is planned at the sidetrack depth to provide an area optimal for setting and retrieving the whipstock. The tangent section is planned to be long enough for the primary exit point as well as a contingency exit in the joint above, should the primary exit fail. The reservoir section in the motherbore and the lateral are drilled with an 8 1/2-in. (22-cm) bit. Both the motherbore and lateral sections are stimulated with 15% hydrochloric acid using an acid jetting assembly on drill pipe. The motherbore section is stimulated prior to setting the lower isolation packer which also serves as the whipstock anchor. The whipstock is installed, the casing window milled, and the lateral is drilled. The lateral is stimulated prior to pulling the whipstock and completing the well.

Completion design Reservoir control is important for both production and injection wells in the current development plan, so individual control of each lateral was

74 Offshore February 2009 • www.offshore-mag.com

0902off_74 74

2/11/09 3:28:37 PM

DRILLING & COMPLETION

a requirement from the outset of the multilateral well justification process. Due to the extreme trajectory of the wells, manipulation of interval control valves (ICVs) with conventional slick-line is not possible and is limited with coiled tubing. Throughout much of the development plan, jackup rigs are in place over many of the wellhead platforms, making access for coiled tubing intervention expensive. For these reasons, surface operated ICVs were selected for installation in multi-lateral wells and multi-zone single lateral wells. A hydraulic system was chosen with a common return line and simple on-off function, although variable choking valves now are available also for installation. The lowermost ICV is a shrouded type which allows it to be positioned above the bottom isolation packer. This offers several advantages over a conventional ICV, including the following: • Saves rig time by a) installing the ICV shallower, and b) avoiding control line feed through the lowermost packer • Avoids the risk of running control lines past the milled casing exit where they could be damaged • Allows installation of the lower-most packer prior to drilling the second lateral. This packer can act as a base for the whipstock and can isolate the first lateral while drilling the second lateral. Hydraulic wet connects could achieve the same result while using a conventional ICV, but with the risk of a bad hydraulic connection in the debris-prone environment of a milled casing exit. To confirm position of the ICVs and to gain information on which lateral is contributing to flow, a permanent downhole pressure/temperature gauge is installed for each lateral as is one for commingled flow in the tubing string.

Implementation The two multi-lateral wells drilled to date in Al Shaheen ﬁeld are water injectors, but are back produced initially, as is standard practice for injection wells in the development. Multi-lateral Well A was a medium-length extended reach trajectory, with both later-

als drilled beyond 15,000 ft (4,572 m) MD in the Kharaib B carbonate reservoir. This reservoir is characterized by a fairly homogeneous permeability distribution with typical values ranging between 5 and 10 md. Despite variance in fluid properties, well liquid Productivity Indices (PIs) generally are evenly distributed around a mean value of 3-5 b/d/ psi. The uniform inflow performance makes the Kharaib B reservoir technically suitable for multi-lateral wells. The first well was a learning experience, and all operations were done with the idea of successfully completing the first multi-lateral well. The drilling team and multi-lateral service provider worked closely to prepare for the job. Operational procedures were scrutinized and “Drill the Well on Paper” meetings were held to ensure everyone in the project was aware of the procedures to be followed. All equipment was laid out in the workshop and inspected prior to sending it out to the rig. The implementation proceeded as planned with only minor operational issues. Multi-lateral Well B was planned as a long extended reach well, with both laterals drilled beyond 25,800 ft (7,864 m) MD in the Shuaiba carbonate reservoir. This reservoir is characterized by large facies variations with permabilities from less than 5 md to several Darcy in the areas dominated by reefs. The location of the line drive pattern in which Multi-lateral Well B was drilled is, however, positioned in a basinal area dominated by a homogeneous permeability distribution with typical values ranging between 5 and 10 md. Fluid properties and therefore liquid PIs also are distributed evenly around a mean value of some 10-15 b/d/psi. The regional uniform inflow performance makes this Shuaiba reservoir location technically suitable for multi-lateral wells. The lessons from the first well were implemented in planning for the second well. The procedures and equipment again were checked prior to the job. The same personnel were involved for the operator and the service provider to assure that all lessons learned from the first well were carried through to the second well.

Front End Experienced Teams ready for your next project. • Field Development • Concept and Feasibility Studies • FEED • Cost Estimates

People Oriented... Project Driven®

Houston • London • Perth • Mumbai www.mustangeng.com Typical completion configuration for a multi-lateral well. www.offshore-mag.com • February 2009 Offshore 75

0902off_75 75

2/11/09 3:28:39 PM

I T ’ S A T O U G H B U S I N E S S . LO O K T O A P I . ®

C E R T I F I C A T I O N

S T A N D A R D S

T R A I N I N G

S a l e s + 1 71 3 - 9 6 4 - 2 6 6 2 | S e r v i c e + 1 2 0 2 - 9 6 2 - 4 7 91 | s a l e s @ a p i . o r g | w w w . a p i . o r g

IT’S TIMES LIKE THESE YOU NEED PEOPLE LIKE US.

AMERICAN PETROLEUM INSTITUTE

0902off_76 76

2/11/09 3:28:40 PM

DRILLING & COMPLETION

The multi-lateral operations were identical to Multi-lateral Well A. The main difference from Multi-lateral Well A to Well B was the length of laterals. The mainbore was drilled to 26,700 ft (8,138 m) MD and the lateral was drilled to 25,880 ft (7,888 m) MD. Extended reach drilling added new questions to the durability of the equipment and to the ability to recover the whipstock after drilling across it for an extended period. However, implementation was without incident.

Case studies Well A Upon completion, Multi-lateral A was produced with both laterals flowing to allow efficient clean up and to enable benchmarking against existing wells. The performance of Multi-lateral A met expectations, with oil production approximately twice that of adjacent wells. Consequently, the well was initially kept on comingled production from both laterals to maximize production. Subsequently, an adjacent well produced with an abnormally high water PI and it was decided immediately to test each lateral (ML1 and ML2) in Multi-lateral Well A selectively to further interpret production performance. Prior to testing, the laterals were shut-in intermittently to accurately determine localized reservoir pressures, thus allowing subsequent calculation of productivity indices. The acquired test data, in terms of liquid, oil, and water PIs, demonstrated a significant performance difference between the two laterals, benchmarked against each other and against typical wells with similar reservoir exposure. Based on typical reservoir homogeneity it was concluded that the PIs of both ML1 and ML2 were the result of a localized secondary permeability, and the difference between the laterals was a consequence of its areal distribution. It was further concluded, considering the repeatability of the observed behavior, that porosity associated with the secondary permeability system was most likely charged with water during shut-ins, then immediately drained when the respective lateral was re-opened for production. Thus, such a mechanism would explain the high and rapidly declining water PI profiles leading to the stabilized PIs representing the total dynamic performance under “equilibrium”, i.e. controlled by the matrix feed rate into the wellbore and into the high permeability system. The identification of an unexpected localized high permeability system initiated a comprehensive review of static and dynamic data, which led to evidence of a similar system in nearby wells. Based on geological and petrophysical characterization, the per-

meability system was interpreted as being the result of a complex network of microfractures providing a substantial enhancement to the conductivity of the carbonate matrix itself. The capability to test the two laterals individually without requiring well intervention or high-resolution pressure gauges enables high-level reservoir characterization in terms of lateral confinement of the distribution of a localized micro-fracture system. The micro-fracture system significantly impacts local fluid dynamics and its identification and delineation carries high significance in planning the remaining well in the area under development. Well B Upon completion, Multi-lateral Well B was produced with both laterals flowing to allow efficient clean-up and to enable benchmarking against existing wells. Performance of Multi-lateral Well B was similar to adjacent producers, which was below expectations considering approximately twice the reservoir exposure. As a consequence of the poorer-than-expected performance, it was decided to immediately test each lateral (ML1 and ML2) in Multi-lateral Well B selectively to further interpret production performance. While testing ML1, two shut-downs were experienced, the first affected only Multilateral Well B while the second affected the entire field. While shutting in Multi-lateral Well B at surface did not induce any change to the ML2 bottomhole pressure build-up trend, a clear response was observed immediately upon field shut down. These observations provided evidence that ML2 was communicating directly to another well. A review of nearby well events was conducted. Based on a combination of pressure and production data, it was concluded that ML2 was linked to nearby Well 7, a planned water injection well which was on back production prior to conversion. Interestingly, this connection bypassed the producer Well 8 in between, indicating that the communication was either at the heel or toe of the well. The instantaneous nature of the pressure response in Multi-lateral Well B ML2 following operation of Well 7 suggests that the communication path is very direct, e.g. through a fracture with practically infinite conductivity rather than through the matrix. The existence of a fracture was unaccounted for, as no drilling, geological, or petrophysical evaluations gave any such indications. The ability to test the two laterals individually without well intervention and the presence of high-resolution pressure gauges has enabled state-of-the-art reservoir characterization in terms of accurately identifying direct

Project Execution Experienced Teams ready for your next project. • Engineering Design • Construction Management • Project Management • Commissioning Support

People Oriented... Project Driven®

Houston • London • Perth • Mumbai www.mustangeng.com

www.offshore-mag.com • February 2009 Offshore 77

0902off_77 77

2/11/09 3:28:41 PM

More Bytes, More Barrels: Business-Driven Innovation

The 2009 Digital Energy Conference and Exhibition will emphasize case studies related to people, processes, and technology issues. The conference will address the challenges of

deployment sustainable strategies Register now at www.digitalenergy2009.com.

7â&#x20AC;&#x201C;8 April 2009 Marriott Houston Westchase Houston, Texas, USA www.digitalenergy2009.com

Gulf Coast Section

0902off_78 78

2/11/09 3:28:43 PM

DRILLING & COMPLETION

Life of Field Experienced Teams ready for your next project. • Debottlenecking • Brownfield Engineering • Operations/Maintenance Support • Laser Scanning Multi-lateral Well B development area.

communication between two existing wells. The existence of interwell communication caused by extreme permeability variance implicates efﬁcient implementation of secondary or tertiary recovery processes. Well interventions typically are required to resurrect adequate reserves recovery. Particularly in multi-lateral wells often with limited or no options for re-entry, such interventions are difﬁcult or impossible, so have a low chance of success at best. The only option with the installed completion is to shut off an entire lateral. In the case of Multi-lateral Well B, the impact of the communication was minimal, as short circuiting of water between two injectors, at least theoretically, should not be critical when occurring without interference with the intermediate producer. These reduced implications in Multi-lateral Well B do not change the fact that the presence of unexpected reservoir geology imposes one of the biggest risks to successful implementation of multi-lateral wells, and reemphasises the need for a thorough candidate selection procedure.

Concluding remarks The ﬁrst two TAML Level 2 multi-lateral wells in Al Shaheen ﬁeld were operational successes from the drilling perspective. All the equipment worked as planned, and there were no lost time or safety incidents. Lessons learned and action items include: • Extensive planning and operations preparation were essential to ensure successful multi-lateral well construction

• Lessons learned during the construction of Multi-lateral Well A were carried forward to Multi-lateral Well B to further enhance success of the operations • Efforts are under way to replace the shrouded ICV with a ball-type ICV, which would remove the flow restriction inherent with shrouded ICVs • The ability to test the two laterals individually without well intervention and the presence of high-resolution pressure gauges has enabled state-of-the-art reservoir characterization giving Multilateral Well A identification and lateral confinement of a localized micro fracture system and in Multi-lateral Well B, accurate identification of direct communication between two existing wells • Unexpected reservoir geology imposes risk on the success of multi-lateral wells and re-emphasises the necessity to implement a thorough candidate selection procedure. 

People Oriented... Project Driven®

Acknowledgement

The authors thank the management of Qatar Petroleum and Maersk Oil Qatar AS for their encouragement and permission to publish this work.

Editor’s note: This article is a summary of the paper presented at PennWell’s Offshore Middle East Conference & Exhibition 2008 in Doha, Qatar. www. offshore-mag.com.

Houston • London • Perth • Mumbai www.mustangeng.com

www.offshore-mag.com • February 2009 Offshore 79

0902off_79 79

2/11/09 3:28:44 PM

DRILLING & COMPLETION

Despite equipment limitations in the region, India’s Jindal Drilling steps forward Chairman D D.P. P Jindal outlines strategy for new technologies Gurdip Singh

Contributing Editor

ndia’s Jindal Drilling & Industries Ltd. is intensifying efforts to introduce new technologies to the sub-continental’s fast expanding quantity of hydrocarbon prospecting acreage. Indian exploration and production companies mainly use conventional technology such as steerable downhole motors, measurement while drilling (MWD), and rotary steerable systems (RSS) offshore. Several operators have experimented with new technology, but their use and outcome are attributable to some speciﬁc campaigns only. Likewise, Jindal Drilling has been performing a range of directional drilling. “We have been drilling high drift relief wells, high angle, horizontal sidetrack wells, etc.,” said chairman D.P. Jindal in an interview with Offshore. The company has built a network of international directional drillers with equipment and tools and has established a dedicated drilling team, he pointed out. Jindal Drilling provides services with steerable downhole mud motors, MWD, logging while drilling (gamma and resistivity), and deviation measurement service like gyro service, among others. However, Jindal noted a major issue as far as new technology is concerned. “Unless a strong, undiluted, and dedicated push is made in this area, we can forget about the excellent business performance we have at the moment,” Jindal said. “From our experience, we can see that only used and rejected technologies are being made available for free and open sale. We have to reduce dependence on these technologies.” He emphasized the need to provide the maximum equipment available to operators to help reduce downtime due to downhole equipment/tool hole failure. The company is on par with its competitors with focus on research and development relating to equipment and tools, operating procedure, operational planning, proper maintenance, and training. Presently, Jindal Drilling’s Research & Development team is

Jindal took delivery of jackup Virtue I from Keppel FELS in December for a five-year contract with ONGC.

working on developing indigenous components for better product quality, especially to replace imported components. “We have also covered aspects like developing as well as outsourcing a few effective and cheaper options for land and offshore operations,” he said. Jindal acknowledged that technology remains a monopoly of the industry giants and those strong R&D teams have been working on product innovations for the past few decades. “Whereas we are a service provider of proven technology and are focused on our core activity, which is better service and less downtime,” stressed Jindal. He also noted that the giants and multi-nationals would have to protect their business interest and as such they have restricted access to their proprietary technologies. Nevertheless, many international companies do opt to tie up with local companies that offer the competitive advantage of being domestic. Jindal Drilling is looking for technology partners, he said, adding

80 Offshore February 2009 • www.offshore-mag.com

0902off_80 80

2/11/09 3:28:46 PM

Extended Reach. Precise Placement. Geosteer highly complex, extended reach, lateral branch along ultra-thin oil column to 7,230 m (23,720 ft), including ﬂat 135° azimuth turn at horizontal, precisely navigating relative to the oil-water contact.

Environment:

Sognefjord sandstone with hard calcite stringers, Troll Field, Norwegian North Sea.

Technology:

INTEQ AutoTrak™ X-treme™ RCLS with integrated MWD/LWD and CoPilot™ Real-time Drilling Optimization.

Answers:

Increased recoverable reserves by accessing complex oil reservoir while precisely navigating 4,872 m (15,984 ft) horizontal step out within 18 inches of oil-water contact for a measured depth of 4.5 miles; delivered 100% ROP improvement through calcite stringers and 17% increase in distance drilled per bit run.

Objective:

0902off_81 81

One thin oil column. Just four and a half more miles to go. Get precise, extensive answers at AnswersWhileDrilling.com/AutoTrak

2/11/09 3:28:50 PM

DRILLING & COMPLETION

that the company has disciplined and committed scientific manpower with flexibility to adapt to operating and managing new technologies immediately. Also, the Indian market is ready to pay for the high cost of top-end technologies, added Naresh Kumar, Jindal Drilling managing director. Changes are due to globalization of the Indian economy, awards of more and more blocks, and the opening of new frontier acreages, especially deepwater prospects, Kumar said. The increasing presence of international E&P operators has also brought about a significant change to the Indian hydrocarbon prospecting business. The Indian market is changing structurally from the state-owned oil and gas players to the private sector, most of which are at the early stages of oil and gas exploration. “The real picture will come into being once operators begin their commercial phase of the drilling campaign,” said Kumar. He also pointed out that technology by

(Left) D.P. Jindal, chairman. (Right) Naresh Kumar, managing director.

million in investments in two jackup rigs as part of its asset expansion plans. Jindal Drilling has operated offshore India for 20 years by chartering rigs from international operator Noble Drilling. Asked about Jindal Drilling’s asset building targets, Jindal said, “The sky is the limit. But we want to move forward progressively, taking each stage at a time as each business opportunity comes along.” Jindal Drilling operates ﬁve offshore rigs. The company operates in the Indian offshore sector in partnership with Noble Drilling

Though Jindal Drilling is enlarging rig asset acquisition based on new drilling contracts, Kumar acknowledged that it has to be a state-of-the-art rig and taken on as soon as a contract is in sight. Elaborating on the chairman’s business strategy to take Jindal Group forward, Kumar said he believes India’s offshore sector will continue to be bullish especially for prospecting new hydrocarbon reserves in deepwater basins. A number of new drilling contracts are being negotiated and Jindal Drilling expects to order new rigs as soon as these contracts are operational and new contracts can be executed, Kumar said. Kumar is banking on the highly intensiﬁed exploration activities in the 94 million sq km (36 million sq mi) Indian offshore sector, some 40% of which is being lined up for oil and gas prospecting in the coming years. “There is an immediate need to add at least four more deepwater semisubmersible rigs offshore India, which currently has about eight rigs in operation,” said Kumar,

The Indian market is changing structurally from the state-owned oil and gas players to the private sector, most of which are at the early stages of oil and gas exploration. default takes its upward trend irrespective of the oil price, which is a very temporary phenomenon. “Time always demands more and technology goes with time. Technology grows faster with the increasing difﬁculties, limitations, restrictions, and stipulations in any sector,” Kumar told Offshore. “Technology shall also take its own course of development.” In coming times, due to the increased geographical, geological, environmental, and economic limitation and stipulations, all E&P companies will opt for directional/deviated wells, said Kumar. “The conventional perception that ‘directional drilling is costly’ will be subdued by much higher hydrocarbon recovery attained by directional wells,” he pointed out. “Oil price mechanism will keep on changing due to the demand/supply situation. Human civilization’s dependency on hydrocarbon and their endeavor of extracting maximum hydrocarbon shall always drive the desire and demand for technologies.” In 2008, Jindal Drilling and its joint venture partners have completed about $380

with whom it has chartered three rigs – Noble Ed Holt, Noble Charlie Yester, and its latest three-year Oil and Natural Gas Co. (ONGC) contract for the Noble George McLeod*I. The jackup Discovery-1, christened at Keppel FELS in Singapore in September 2008, started its three-year drilling contract with ONGC in October. The second jackup, Virtue-1, commissioned in December, has a five-year contract with ONGC. Both rigs will be involved in ONGC’s development drilling and well workover programs on the western coast of India, especially around the highly prolific Mumbai High basins, where a number of recent discoveries are in the development planning stage. Kumar is confident the two fixed-term ONGC contracts will be renewed for the new high-speed rigs, Jindal Drilling’s first rig-ownership investments. Going forward, Jindal Drilling plans to add more rigs, both jackups and deepwater drillers, as it seeks more and more exploration and mining contracts in India as well as other parts of Asia and the Middle East.

who plans a deepwater rig investment as the next addition to Jindal Drilling assets. Kumar also disclosed that Singapore would be the Jindal Group’s Asian base, having already established two joint venture companies – Discovery Drilling Pte Ltd. and Virtue Drilling Pte Ltd. – for operating the two new rigs out of the city/state. The two companies also expect to make separate initial public offers for listing on the Singapore Exchange at the appropriate time in order to fund future acquisitions. Kumar said he believes Singapore is suitable for developing Jindal Group’s international businesses and offers good long-term opportunities to raise financing. The Delhi-based Jindal Group, which is involved in rig operations and seamless pipe supplies to the Indian oil and gas sector, has projected annual revenue and profit growths of more than 50% for the financial year March 2008-2009 and 2009-2010. The company aims to double its annual earnings to $1.25 billion by 2011 from the 2008 level, however, bearing the effects of current global economics, Kumar said. 

82 Offshore February 2009 • www.offshore-mag.com

0902off_82 82

2/11/09 3:28:51 PM

𰁊𰁞𰁛𰀖𰁅𰁜𰁜𰁩𰁞𰁥𰁨𰁛𰀖𰁊𰁛𰁙𰁞𰁤𰁥𰁢𰁥𰁝𰁯𰀖𰀹𰁥𰁤𰁜𰁛𰁨𰁛𰁤𰁙𰁛𰀕𰁞𰁨𰀕𰁩𰁝𰁚𰀕𰁬𰁤𰁧𰁡𰁙𰃉𰁨𰀕𰁛𰁤𰁧𰁚𰁢𰁤𰁨𰁩𰀕𰁚𰁫𰁚𰁣𰁩𰀕𰁛𰁤𰁧𰀕𰁩𰁝𰁚𰀕𰁙𰁚𰁫𰁚𰁡𰁤𰁥𰁢𰁚𰁣𰁩𰀕𰁤𰁛𰀕𰁤𰁛𰁛𰁨𰁝𰁤𰁧𰁚𰀕𰁧𰁚𰁨𰁤𰁪𰁧𰁘𰁚𰁨𰀕𰁞𰁣𰀕𰁩𰁝𰁚𰀕𰁛𰁞𰁚𰁡𰁙𰁨𰀕𰁤𰁛𰀕𰁙𰁧𰁞𰁡𰁡𰁞𰁣𰁜𰀡𰀕𰁚𰁭𰁥𰁡𰁤𰁧𰁖𰁩𰁞𰁤𰁣𰀡𰀕𰁥𰁧𰁤𰁙𰁪𰁘𰁩𰁞𰁤𰁣𰀡𰀕𰁖𰁣𰁙𰀕𰁚𰁣𰁫𰁞𰁧𰁤𰁣𰁢𰁚𰁣𰁩𰁖𰁡𰀕𰁥𰁧𰁤𰁩𰁚𰁘𰁩𰁞𰁤𰁣𰀣

𰁆𰁢𰁗𰁤𰀖𰁪𰁥𰀖𰁗𰁪𰁪𰁛𰁤𰁚𰀖𰁤𰁥𰁭𰀗𰁭𰁭𰁭𰀤𰁥𰁪𰁙𰁤𰁛𰁪𰀤𰁥𰁨𰁝𰀥𰀨𰀦𰀦𰀯

0902off_83 83

2/11/09 3:28:53 PM

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

Aker monohulls to take on wider range of intervention tasks Support role also could improve rig productivity Nick Terdre

Contributing Editor

step-change in subsea well intervention is imminent. Aker Oilfield Services has ordered four newbuild vessels to extend the range of services it plans to offer. The first, due for delivery in early 2010, already has a long-term contract with Petrobras. Cost-effective subsea well intervention is critical for the offshore industry for several reasons. One is the rapid increase globally in subsea production wells, many of them in deep waters. Another is the need to tap additional reserves – recovery from subsea wells is currently around 30-40% lower than from platform wells. Other factors driving developments in intervention are the need for production worldwide to keep pace with growing demand, and the growing restrictions on international oil companies trying to access new reserves. Traditionally mobile drilling rigs provide the platform to maintain subsea wells, but as day rates have climbed, oil companies are increasingly keen to reserve rigs for the core business of drilling. Alternative solutions for subsea well intervention are therefore in strong demand. So far the service industry’s response has been limited to the provision of light well intervention services from monohull vessels, says Erik Norbom, chief technology officer for Aker Oilfield Services. Also, these services have been applied only in water depths of up to 450 m (1,476 ft). Aker, however, is designing its new service for all water depths up to 3,000 m (9,842 ft). “Our mission is to come up with a solution which is also attractive in price and therefore helps increase the frequency of intervention operations,” says Norbom. That solution involves an expanded range of services delivered from monohull vessels specially designed for this task. The aim is to provide these services for about half the

Aker Oilfield Services’ OSCV 06, classed as a MODU, is designed for heavier subsea well intervention tasks including some drilling functions and well testing.

equivalent cost using a drilling rig. While the latter is essential for drilling and installing tubing, Aker also envisages its vessels taking on other tasks such as through-tubing drilling and well clean-up.

Development background Aker Oilﬁeld Services, which is owned 77% by Aker group companies and 23% by DOF Subsea, was established in 2006 to provide improved oil recovery services for subsea wells. Its partners within the Aker group are Aker Solutions and its subsidiary Aker Well Service, and Aker Qserv, an Aberdeen-based provider of well intervention services which was acquired in 2008. Offshore ship owner and operator DOF Subsea and well services company Expro also are participating. Aker Solutions has been developing subsea well intervention technology and providing associated operations personnel since the early days, according to senior vice president for business development and technology, Erik Taule. Its achievements include open-water workover systems that dispense with the need for the 21-in. (53.3-cm) marine riser traditionally applied to encase the high-pressure riser used to ﬂow oil from the well.

The company is providing wireline services and equipment for both light and heavy intervention from drilling rigs on several fields, including the Troll Oil field and the high-pressure, high-temperature Kristin field in the Norwegian sector, both operated by StatoilHydro. In partnership with Island Offshore, it is also a leading provider of monohull-based wireline intervention services. The rig-based operations employ modular well control packages which have been repackaged for use on monohull vessels, and these form the basis for the packages to be used in the new service, Taule says. Services to be offered by Aker Oilfield Services and its partners are as follows: • Subsea intervention: The installation, testing, and maintenance of subsea modules and top-section downhole equipment • Riserless well intervention: Logging, reperforation, zonal isolation through plug-setting and removal • Riser-based intervention: Coiled tubing and wireline operations, well testing and clean-up, chemical injection, circulation, sand removal, push force, and scale milling

84 Offshore February 2009 • www.offshore-mag.com

0902off_84 84

2/11/09 3:37:08 PM

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

The first vessel built to the OSCV 03 design has been chartered by Petrobras to provide services as a subsea equipment support vessel.

• Light drilling: Through-tubing drilling with coil and downhole motor, through-tubing rotary drilling with slim-pipe, and managed-pressure drilling. These services will be provided from dedicated monohull intervention vessels based on designs developed by Aker Yard, now STX Europe, to meet specifications provided by Aker Oilfield Services and Aker Solutions. An order has been placed with the shipbuilder for four vessels, plus two options. These vessels, to be operated by DOF, are being built to the offshore subsea construction vessel designs OSCV 03 and OSCV 06. Both designs are unusually long – OSCV 03 is 121 m (397 ft) and OSCV 06 is 157 m (515 ft). In the latter case, this allows the 06 to ride three wave lengths at a time. Model tank tests at the Marintek facility in Trondheim, Norway, confirmed that this feature improved the vessel’s stability, which translates into longer uptime.

Another unusual feature is the lowered bow, in which the helideck is contained. Most offshore support vessels have the helideck above bridge level, but in this case the bridge overlooks the helideck. That should make helicopter landings easier and also possible in worse sea states than with a conventional, high-up helideck. Behind the bridge is a large deck area supporting a moonpool, derrick, and crane, with ample room to carry equipment and perform operations. The OSCV 03 has a deck area of 1,300 sq m (13,993 sq ft) while the OSCV 06 has a deck area of 2,100 sq m (22,604 sq ft) and a deckload capacity of 7,000 metric tons (7,716 tons). Accommodation capacity is for 120 on the OSCV 03 and 140 on the OSCV 06. Both vessels have DP-3 dynamic positioning capability and are equipped with two work-class ROVs. OSCV 06 has a transit speed of 19 knots, enabling it to move swiftly between locations. The current building program involves one OSCV 03 vessel and three OSCV 06 units. The hulls for the four vessels have been contracted to STX Europe’s shipbuilding facility in Romania. The OSCV 03 will be outﬁtted at Aukra and the three OSCV 06 vessels at Sørviknes, two yards on the mid-Norwegian west coast. Recently the hull of the OSCV 03 unit was on its way to Aukra, while construction of the hull of the ﬁrst OSCV 06 was well advanced and steel was being cut for the second. The OSCV 03 is due to be delivered in early 2010, and the OSCV 06 vessels later in 2010 and in early 2011.

Differing roles The two designs are intended for somewhat different functions. The OSCV 03 is classed as a construction vessel, while the OSCV 06, which will undertake operations involving oil on deck, is classed as a mobile offshore drilling unit (MODU).

Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind mperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temp ure, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature umidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Hum y, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, ecipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Preci tion, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitatio olar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Sola adiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radi on, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, tmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atm pheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmosphe essure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Presre, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind mperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temp ure, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature umidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Hum y, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, ecipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Preci tion, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitatio olar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Sola adiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radi on, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, tmospheric mosp p n, Atm pheric heric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmosphe mosphe p Presessure, ssur Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric ic Pres re, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, e, W essure Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind nd, T e, Win mperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temp mper p d, Tem ure, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature re, H eratur umidity, midi Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, e, H Hum um Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, y, Prec midity, y ecipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Preci cipit p y y, Prec tion, on, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitatio ipitatio p olar ar R Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, n, Sola adiation, diatio Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar ar Radi Rad on, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, n, At diation tmospheric mosp p Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, n, Atm pheric heric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmosphe mosphe p essure, ssur Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric ic Pres Presre, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, e, Wind, W essure Wind, nd, T Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, e, Wind Win mperature, mper p Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, d,, T Temp em ure, re, H Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature eratur umidity, midi Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, e, Hum Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, y, Prec midity, y ecipitation, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Preci cipit p y y, Prec tion, on, Solar Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitatio ipitatio p Radiation, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, olar ar Ra n, Sola adiation, Radi diatio Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar arr R Rad on, Atmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, n, At ttion tmospheric Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, A mosp sp p Atm pheric hericc Pressure, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmosphe ssphe p Presessure, ssur ur Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric P Pres re, Wind, Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, e, W sssure Temperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind Wind, nd, T e e, W Win mperature, Humidity, Precipitation, Solar Radiation, Atmospheric Pressure, Wind, Temp mper p d, Tem S l R di i A h i P Wi d T H idi P i i i

Meteorological Instruments

0902off_85 85

2/11/09 3:37:10 PM

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

For Petrobras, the OSCV 03’s primary role will be as a subsea equipment support vessel (SESV), a concept originated by the Brazilian company and further developed in cooperation with Aker Oilﬁeld Services. This designation does not involve well intervention as such, but does mean taking on work traditionally performed by drilling rigs, in particular installing subsea trees. The trees employed by Petrobras consist of three main parts: a production adapter base, christmas tree, and an external tree cap. Three runs are therefore needed to install the entire tree, and for a drilling rig running each part on the drill-pipe in, for example, 2,000 m (6,562 ft) of water, the whole operation typically takes several days. The SESV, however, runs each part guideline-less on ﬁber rope, using a specially designed installation tool. According to Norbom, it should take no more than around one hour for each run; but even if it takes a little longer in practice, the time-saving still will be substantial. The SESV also will perform light marine construction – what is referred to as subsea intervention – and tie-ins. It is capable of landing modules weighing up to 125 metric tons (138 tons) in 2,500 m (8,202 ft) water depth. Tooling for the installation of subsea

trees and for subsea intervention operations is being developed by Aker Solutions.

Multi-assignment capability In size the 06 design is not far short of a small drillship, Norbom points out. Its equipment includes a top-drive system for the drilling functions. Riser work will be performed with high-pressure workover risers – a 7-in. (17.8-cm) riser for water depths to 2,000 m, and 5-in. (12.7-cm) for deeper operations to 3,000 m. Aker Oilfield Services designed the vessel to be multipurpose – its attractions are enhanced if clients know it can be deployed on other tasks when the flow of subsea well intervention work is interrupted. The design therefore also includes a 400-metric ton (441ton) crane, providing the capability to install structures weighing up to 225 metric tons (248 tons) in water depths to 3,000 m. This also allows the vessel to be self-sufficient when lifting heavy equipment on board, a big advantage when operating in areas short of local infrastructure, Norbom says. The OSCV 06 also is equipped for well testing and clean-up, functions typically performed by drilling rigs. It is fitted with a flare at the stern for burning off produced hydrocarbons. Using the vessel for this task can save 10-14

days’ rig-time, he adds. The facilities will have capacity to produce up to 20,000 b/d of oil and 4 MMcm/d (141 MMcf/d) of gas. In both new vessel designs, operations are managed from one integrated control room. Here there are three main control chairs – one for wireline and coiled tubing operations, another for well control, and one for the topsides equipment. Other work stations are assigned for handling third-party equipment, tooling, and so on. “In other words,” says Norbom, “all the control operators are sitting in one room, talking together, and looking at the same screens.” In this way, integration of operations should be more efficient and safer. Potential clients have responded positively to presentations of the overall subsea well intervention concept, he adds. “They can see the possibility of significant cost savings.” He is optimistic of winning further contracts by the time the vessels come into operation. Clients seem to have in mind long-term charters of at least five years. Typically these might be the larger international oil companies with a substantial inventory of subsea facilities to maintain. But Aker Oilfield Services says it is open to collective contracts with groups of smaller companies, along the lines of the multi-client drilling rig contracts common today. 

Computational Flow Assurance Risk Mitigation & Performance Improvement Flow, Thermal, Stress 3D Simulation Software & Services • STAR-CCM+ • STAR-CD • STAR-CAD Series

at: Visit us

Subsea009 2 Tiebac03k-05, 2009.

7. March Booth 56 nio, TX. : VD D San Anto EE ur FR yo Pick up and Stress Thermal 3D Flow, ns for the tio lu So n Simulatio Industry Oil & Gas

For more information on Flow, Thermal & Stress Simulation, please visit: www.cd-adapco.com Or contact: info@us.cd-adapco.com

0902off_86 86

www.cd-adapco.com

2/11/09 3:37:27 PM

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

SUBSEA TIEBACK FORUM & EXHIBITION

THE DEEPEST SHOW ON EARTH March 3 - 5, 2009 Henry B. Gonzalez Convention Center | San Antonio, TX

SUBSEA TIEBACK FORUM & EXHIBITION

PennWell invites you to the 9th annual Subsea Tieback Forum & Exhibition. SSTB has become the premier event for one of the fastest growing sectors of the offshore oil and gas industry. This year’s SSTB is scheduled for March 3 – 5, 2009 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. This year’s theme is “The Deepest Show On Earth.” As our industry changes, the sharing of knowledge and collective experiences becomes more and more crucial to improving the quality, safety, and economics of the subsea tieback industry. The conference board will once again solicit a number of key presentations by industry leaders. As in the past, only by participating in this conference will you be able to receive its benefits, as proceedings will not be published and no Press is ever allowed in the conference area. This is truly a closed forum with open discussion, where the information shared inside the conference room stays inside the conference room. We hope you will join us.

Owned & Produced by:

0902off_87 87

Flagship Media Sponsors:

Supported by:

Hosted by:

2/11/09 3:37:29 PM

SUBSEA

Challenges of the Jansz deepwater tieback Debris, scarp, shore crossing make project difficult arge diameter, deepwater pipelines are a significant part of total project cost, so optimizing routes was required from both installation and operations cost viewpoints for both the Gorgon and deepwater Jansz fields off the northwest coast of Barrow Island, Western Australia. Routing the pipelines between Jansz and the onshore LNG facilities was a challenge because of the 1,350 m (4,429 ft) water depth and the need to avoid debris fields. Traversing the scarp on the way to shallow water and the shore crossing at Barrow Island turned out to be the most challenging. Early in FEED, analysis of seismic records from the exploration phase identified signifi-

David Equid

Gorgon Project cant seabed irregularities at Jansz, massive blocks left as a debris ﬁeld following a catastrophic failure of the scarp closer to the island. This raised concerns with stability in sections of the scarp and exposure of the pipeline to damage following any failure. Soliton (internal) waves that periodically occur on the North West Shelf affect both pipeline installation and the stability of completed pipelines. Little was known of Solitons along the proposed pipeline route. Initiating events and the peak magnitude of the cur-

rents associated with breaking Solitons were not well known. Offshore data collection by the project combined with extensive modeling reduced the uncertainty surrounding these events to an acceptable level. The ability to transport the liquids and fines associated with production from Jansz up the potentially steep inclines along some sections of the scarp was unknown. No dependable way to predict this flow within the inclined sections was known. Finding a viable route to address these obstacles was a challenge, but one was found -the 170 km (106 mi) “southern” route. A shorter, more cost effective “northern” route had been identified but this would require crossing the scarp in an area with slopes up to 70º. Analysis of survey data combined with detailed modeling confirmed that the scarp was geologically stable in this location, and further work using both analysis and modeling determined that the fines and liquids from Jansz would flow up the inclined pipe along with the gas. The final selection of an optimized “northern” route represented not only a viable solution to the routing question but also realized significant cost savings relative to the initial concepts.

Route selection

Seabed profiles at Jansz.

Pipeline routes and scarp features.

The development concept for Jansz is based on an all subsea, full wellstream-tobeach configuration. This selection resulted from initial concept development work by ExxonMobil and was validated independently by Chevron. A revalidation by the project team in 2006 part way through FEED, utilizing more comprehensive design and cost data, confirmed that this was the most cost effective and technically viable basis for joint development of Jansz and Gorgon fields. To connect the LNG plant on Barrow Island to the deepwater Jansz location, the pipelines need to transition from 1,350 m (4,429 ft) up onto the continental shelf at maximum depths of about 250 m (820 ft) across an underwater scarp. Prior seabed surveys by Gorgon Joint Venture members showed that the scarp on the direct route to Jansz had slopes of up to 70º. In addition, early work indicated the scarp might be unstable in these regions, especially in the area around the Chrysaor canyons where active movement of seabed material had been noted.

88 Offshore February 2009 • www.offshore-mag.com

0902off_88 88

2/11/09 3:37:03 PM

SUBSEA

inclination is approximately 70º and the scarp or cliff height about 100 m (328 ft).

Alternate route development

(Above) Alternate Jansz routes. (Right) Breaking Soliton wave representation.

To avoid these features, a longer southern route that did not cross the steep sections of the scarp was identified. It added 45 km (71 mi) to the length of the direct route. The lower angled slopes along the southern route were not considered to be flow assurance issues An extensive geophysical and geotechnical survey in 2005/6, gathered data along potential pipeline routes, scarp crossing, and subsea structure locations. This survey was managed by Chevron, supported by technical specialists from ExxonMobil. Approximately 5,550 km (3,449 mi) of survey lines including 2,500 km (1,553 mi) of deepwater reconnaissance, 2,200 km (1,367 mi) of detailed deepwater survey, and 100 large gravity piston cores and boreholes were involved. Data confirmed the validity of the southern route and also helped identify shorter northern routes. Detailed seabed profile assessments along the routes, pipeline mechanical design, installation analysis, and geohazard modeling based on results from geophysical data and core analysis (palaeo age dating) were conducted for each potential route to Barrow Island. In parallel with the seabed survey, a separate program collected metocean data along potential pipeline routes. Soliton waves, a tidal current phenomenon in the North West Shelf at the boundary between warm and cooler streams could pose issues during the installation and operation of the pipelines. The 12 months of data collected was combined with approximately three years of prior data as the basis for building models to predict local seabed currents as input to the pipeline stability analysis. This data was the basis of the project’s contribution to the Northern Australia Soliton Study (NASS) Joint Industry Project, which developed a model to predict Soliton waves – likely sources, direction, and magnitude – along proposed routes. The conclusion from the NASS work was that due to the obtuse angles at which tides approach the Jansz/Gorgon area, their Soliton generating effects are not as great as those at Rankin, for instance, where the tides arrive perpendicular to the bathymetry. The 10-year return period Solitons were determined to not exceed the 10-year non-cyclonic design criteria, nor are the 100-year return period Solitons expected to govern the stabilization design. By 2006 work had confirmed viability of the southern route. The project team confirmed a successful installation could be done, taking account of pipeline design and geo hazard risks, and this southern route formed the basis for the initial round of project cost estimates. Focus then turned towards route optimization and identification of northern route alternatives. A route passing just north of Gorgon was developed that used a section of the scarp where the maximum

Northern routes had challenges related to: • Transport of well fines up steep inclined pipelines • Long term acceptability of any resultant “super spans” • Ability to pre-trench the top of the scarp to reduce the span length. The costs for any remedial work (such as routine pigging during operation) might negate the initial cost savings of the shorter pipeline. A two-stage program evaluated the transport of expected fines production from Jansz up the inclined section of pipe at the scarp crossing. Numerical analysis combined with physical model testing coordinated by Chevron demonstrated with high confidence that within the expected range of flowrates in the lines, the predicted sizes of fines will be transported through the deepwater pipeline section and up the scarp. The effect of the differing slopes between the identified northern and base case southern routes was insignificant. The pipeline design team evaluated the predicted span at the scarp crossings. To reduce span length it was proposed that a trench be cut at the scarp shoulder, adjusting the exit angle of the pipeline and effectively reducing the height and length of the resulting span. The construction of a trench through the over consolidated calcareous soils at the scarp required detailed assessment, as this soil has very different characteristics to usual deepwater soils. Laboratory testing of samples collected at the scarp, combined with site specific offshore geophysical and geotechnical investigations, confirmed the soils are trenchable. This investigation and evaluation resulted in a number of feasible design options. The new analysis processes applied to the different sections of line, including the portion where the crossing of the scarp occurs, resulted in the selection of the northern route as the basis for the project. This routing realized installation cost savings as well as improvements in the operability of the overall subsea system due to the shorter pipeline lengths and the associated reduction in flow-related back pressure on the wells. The Jansz-Io feature was identified during the 1996 North West Shelf offshore acreage gazettal, delineated in a 2D seismic program in 1997, and confirmed by the Jansz-1 exploration well in 2000. A second well, Io-1 was drilled into the same feature in 2001. Further wells, Jansz-2 and Jansz-3, were drilled in 2002 and 2003, respectively, and a detailed 3D seismic survey acquired over the area in 2004. This exploration sequence confirmed the presence of a world class gas resource. In January 2004, a Cooperative Development study by ExxonMobil and Chevron evaluated a range of development options for the combination of the Jansz and Gorgon fields, and led to the current project – joint development of the fields based on an all subsea development, tied back via full wellstream pipelines to a multi-train LNG plant on Barrow Island.  Editor’s note: This article is a summary of the paper presented at PennWell’s Deep Offshore Technology International Conference & Exhibition 2008 in Perth, Australia. www.offshore-mag.com. www.offshore-mag.com • February 2009 Offshore 89

0902off_89 89

2/11/09 3:37:05 PM

FLOWLINES & PIPELINE

How to overcome challenges with active electrical heating in deepwater They are also the only projects with water depth lectrical heating of thermal insulated L. Delebecque exceeding 500 m (1,640 ft). These two projects pipelines to prevent hydrate formation E. Sibaud have highlighted the current technological limand wax deposition in subsea oil producM. Scocard itations of DEH system (length, water depth, tion has proven to be technically and C. Rueda power demand) and have consequently asked economically viable in shallow water apP. Delbene for extensive qualification activities. plications. Saipem s.a. (France) Based on Saipem experience, Direct Electrical Heating (DEH) is the preferred solution Technology challenges compared to indirect heating or hot fluid circuDEH raises various design challenges, in lation configurations (bundle or pipe-in-pipe). particular electromagnetic and mechanical isSaipem has been working to adapt DEH to deep waters and finds sues, as well as corrosion concerns. installation is the critical point and probably the most challenging Complex electromagnetic phenomena impact system design and technical issue. The company has developed installation procedures eventually affect installation. These phenomena include: and cost-effective solutions to ensure reliable and safe J-lay installa• The distance between the cable and the pipeline impacts the tion of DEH systems. mutual inductance of the system parts. A larger distance beThe current trend offshore is to go beyond traditional frontiers tween pipeline and cable increases power requirements. So, the to produce smaller fields in deeper waters, farther away from main cable must be as close as possible to the pipeline. fields, and with challenging fluids. The high pressure and low sea bot• Metal between the cable conductor and the pipeline reduces tom temperatures (around 4° C or 39º F) met in these scenarios lead system efficiency. Therefore, the piggybacked DEH cable is to the formation of hydrates and/or the deposit of wax in the case of not armored, making it fragile for installation and operations. paraffinic oils. These solids can block flowlines. The metal reinforcement of any concrete weight coating to the Up to now, DEH has been used for flowlines only. It has been pipeline must also be considered and metallic ore to increase the identified as a quite mature and robust technology among heating density of concrete should be discounted. solutions in the case where it is coupled with a wet insulation. • One major issue for DEH systems is the low mechanical resistance of the power cable. It is sensitive to stretching, crushing, and abrasion. Full integral mechanical protection of the cable DEH concept may be required for some projects where the risk of cable damDEH is based on the fact that an electrical alternating current age is critical. (AC) in a metallic conductor (i.e. cable, pipe) generates heat (Joules effect). In the direct pipe heating system, the pipe to be heated is an active conductor in a single-phase circuit, together with a single core Olowi field application power cable as the forward conductor, located in parallel with and DEH has been selected for use in the Olowi oil and gas field 18 close (“piggyback”) to the heated pipe. km (11 mi) offshore Gabon. Canadian National Resources InternaFrom the platform power supply, two riser cables provide the tional is operator. electric power to the heating system. One of the two single-core Saipem is in charge of design, procurement, and installation of three riser cables (return cable) is connected to the near end of the pipe, heated 10-in. (25-cm) pipelines in shallow water. The pipeline with DEH and the other (feeder cable installed in “piggyback”) to the forward system will be installed in 2009 by S-lay installation vessel Castoro 2. conductor which is connected to the other end of the pipe. The heating system is electrically connected (“earthed”) to the Power cable surrounding seawater through several sacrificial anodes for a length Straps of about 50 m (164 ft) at both ends where the cables are connected, Topside called “Current Transfer Zone.” Steel structures must be avoided power supply in these zones, and bracelet anodes are required along the running Thermally insulated length at fixed intervals. pipe Power supply Given the loss in seawater and depending on the heating requirecables ments and length of the flowline, DEH system can reach heavy ratings up to current around 1500A and insulation voltage up to 52kV. Power cable/ DEH systems are on several subsea pipelines in the North Sea Connection piggy-back Connection including Asgard, Huldra, Kristin, and Norne. These are in shallow water (less than 400 m or 1,312 ft). For these, the U-value range is usually between 3 W/m²K and 8 W/m²K, enabling conventional wetinsulation coating and a power requirement range between 1 mW Current transfer zone Well stream pipe Current transfer zone and 2 mW. These projects are also characterized by high current anodes on pipe anodes on pipe rate and large power cable cross section. Tyrihans is characterized by a long flowline and associated a high power demand. The Ormen Lange power cable will be a retrofit. Direct Electrical Heating and cable in “piggyback” arrangement.

90 Offshore February 2009 • www.offshore-mag.com

0902off_90 90

2/11/09 3:37:39 PM

BJ’s Ice-Chek™ inhibitor system allows you

to treat gas hydrates,

without burning the budget.

BJ Services’ Ice-Chek™ technology provides cost-effective ﬂow assurance. 𰀶𰁔𰁊𰁏𰁈𰀁𰀣𰀫𰂵𰁔𰀁𰀪𰁄𰁆𰀎𰀤𰁉𰁆𰁌𰂊𰀁𰁊𰁏𰁉𰁊𰁃𰁊𰁕𰁐𰁓𰀁𰁔𰁚𰁔𰁕𰁆𰁎𰀍𰀁𰁐𰁑𰁆𰁓𰁂𰁕𰁐𰁓𰁔𰀁𰁄𰁂𰁏𰀁𰁓𰁆𰁅𰁖𰁄𰁆𰀁𰁕𰁉𰁆𰀁𰁄𰁐𰁔𰁕𰀍𰀁𰁍𰁐𰁈𰁊𰁔𰁕𰁊𰁄𰁂𰁍𰀁𰁂𰁏𰁅𰀁𰁔𰁂𰁇𰁆𰁕𰁚𰀁𰁄𰁐𰁏𰁄𰁆𰁓𰁏𰁔𰀁𰁂𰁔𰁔𰁐𰁄𰁊𰁂𰁕𰁆𰁅𰀁𰁘𰁊𰁕𰁉𰀁𰁎𰁆𰁕𰁉𰁂𰁏𰁐𰁍𰀁𰁈𰁂𰁔𰀁𰁉𰁚𰁅𰁓𰁂𰁕𰁆𰀁𰁄𰁐𰁏𰁕𰁓𰁐𰁍𰀁𰁑𰁓𰁐𰁈𰁓𰁂𰁎𰁔𰀏𰀁𰀧𰁊𰁆𰁍𰁅𰀁𰁂𰁑𰁑𰁍𰁊𰁄𰁂𰁕𰁊𰁐𰁏𰁔𰀁𰁉𰁂𰁗𰁆𰀁𰁔𰁉𰁐𰁘𰁏𰀁𰁂𰁔𰀁𰁎𰁖𰁄𰁉𰀁𰁂𰁔𰀁𰁂𰀁𰀘𰀑𰀆𰀁𰁓𰁆𰁅𰁖𰁄𰁕𰁊𰁐𰁏𰀁𰁊𰁏𰀁𰁕𰁓𰁆𰁂𰁕𰁊𰁏𰁈𰀁𰁗𰁐𰁍𰁖𰁎𰁆𰀁𰁄𰁐𰁎𰁑𰁂𰁓𰁆𰁅𰀁𰁕𰁐𰀁𰁎𰁆𰁕𰁉𰁂𰁏𰁐𰁍𰀁𰁂𰁍𰁐𰁏𰁆𰀏𰀁𰀵𰁉𰁆𰀁𰀪𰁄𰁆𰀎𰀤𰁉𰁆𰁌𰀁𰁊𰁏𰁉𰁊𰁃𰁊𰁕𰁐𰁓𰁔𰀁𰁏𰁐𰁕𰀁𰁐𰁏𰁍𰁚𰀁𰁔𰁕𰁐𰁑𰀁𰁈𰁂𰁔𰀁𰁉𰁚𰁅𰁓𰁂𰁕𰁆𰁔𰀁𰁇𰁓𰁐𰁎𰀁𰁇𰁐𰁓𰁎𰁊𰁏𰁈𰀍𰀁𰁕𰁉𰁆𰁚𰀁𰁄𰁂𰁏𰀁𰁂𰁍𰁔𰁐𰀁𰁅𰁊𰁔𰁔𰁐𰁍𰁗𰁆𰀁𰁉𰁚𰁅𰁓𰁂𰁕𰁆𰀁𰁑𰁍𰁖𰁈𰁔𰀁𰁇𰁐𰁓𰁎𰁆𰁅𰀁𰁃𰁚𰀁𰁕𰁆𰁎𰁑𰁆𰁓𰁂𰁕𰁖𰁓𰁆𰀁𰁐𰁓𰀁𰁑𰁓𰁆𰁔𰁔𰁖𰁓𰁆𰀁𰁄𰁉𰁂𰁏𰁈𰁆𰁔𰀏𰀁𰀤𰁐𰁖𰁑𰁍𰁆𰁅𰀁𰁘𰁊𰁕𰁉𰀁𰀣𰀫𰂵𰁔𰀁𰀥𰁚𰁏𰁂𰀤𰁐𰁊𰁍𰂊𰀁𰁄𰁂𰁑𰁊𰁍𰁍𰁂𰁓𰁚𰀁𰁂𰁏𰁅𰀁𰀪𰁏𰁋𰁆𰁄𰁕𰀴𰁂𰁇𰁆𰂊𰀁𰁄𰁉𰁆𰁎𰁊𰁄𰁂𰁍𰀁𰁊𰁏𰁋𰁆𰁄𰁕𰁊𰁐𰁏𰀁𰁔𰁆𰁓𰁗𰁊𰁄𰁆𰁔𰀍𰀁𰁑𰁓𰁆𰁄𰁊𰁔𰁆𰀁𰁑𰁍𰁂𰁄𰁆𰁎𰁆𰁏𰁕𰀁𰁐𰁇𰀁𰁕𰁉𰁆𰀁𰀪𰁄𰁆𰀎𰀤𰁉𰁆𰁌𰀁𰁊𰁏𰁉𰁊𰁃𰁊𰁕𰁐𰁓𰀁𰁐𰁓𰀁𰁐𰁕𰁉𰁆𰁓𰀁𰀣𰀫𰀁𰁄𰁉𰁆𰁎𰁊𰁄𰁂𰁍𰀁𰁑𰁓𰁐𰁅𰁖𰁄𰁕𰁔𰀁𰁄𰁂𰁏𰀁𰁂𰁅𰁅𰁓𰁆𰁔𰁔𰀁𰁔𰁑𰁆𰁄𰁊𰂾𰁄𰀁𰁅𰁐𰁘𰁏𰁉𰁐𰁍𰁆𰀁𰁑𰁓𰁐𰁅𰁖𰁄𰁕𰁊𰁐𰁏𰀁𰁑𰁓𰁐𰁃𰁍𰁆𰁎𰁔𰀁𰁂𰁕𰀁𰁕𰁉𰁆𰁊𰁓𰀁𰁔𰁐𰁖𰁓𰁄𰁆𰀏𰀁𰀪𰁄𰁆𰀎𰀤𰁉𰁆𰁌𰀁𰁊𰁏𰁉𰁊𰁃𰁊𰁕𰁐𰁓𰁔𰀁𰁉𰁂𰁗𰁆𰀁𰁃𰁆𰁆𰁏𰀁𰁖𰁔𰁆𰁅𰀁𰁔𰁖𰁄𰁄𰁆𰁔𰁔𰁇𰁖𰁍𰁍𰁚𰀁𰁊𰁏𰀁𰁑𰁓𰁐𰁅𰁖𰁄𰁊𰁏𰁈𰀁𰁈𰁂𰁔𰀁𰁘𰁆𰁍𰁍𰁔𰀁𰁂𰁏𰁅𰀁𰁑𰁊𰁑𰁆𰁍𰁊𰁏𰁆𰁔𰀁𰁊𰁏𰀁𰀤𰁂𰁏𰁂𰁅𰁂𰀁𰁂𰁏𰁅𰀁𰁇𰁐𰁓𰀁𰁅𰁆𰁆𰁑𰁘𰁂𰁕𰁆𰁓𰀁𰁄𰁐𰁎𰁑𰁍𰁆𰁕𰁊𰁐𰁏𰁔𰀁𰁂𰁏𰁅𰀁𰁅𰁆𰁆𰁑𰀁𰁈𰁂𰁔𰀁𰁘𰁆𰁍𰁍𰁔𰀁𰁊𰁏𰀁𰁕𰁉𰁆𰀁𰀨𰁖𰁍𰁇𰀁𰁐𰁇𰀁𰀮𰁆𰁙𰁊𰁄𰁐𰀏𰀁 BJ Services𰀁𰁉𰁂𰁔𰀁𰁕𰁉𰁆𰀁𰁔𰁌𰁊𰁍𰁍𰁔𰀁𰁂𰁏𰁅𰀁𰁕𰁆𰁄𰁉𰁏𰁐𰁍𰁐𰁈𰁚𰀁𰁕𰁐𰀁𰁉𰁆𰁍𰁑𰀁𰁊𰁎𰁑𰁓𰁐𰁗𰁆𰀁𰁚𰁐𰁖𰁓𰀁𰁉𰁚𰁅𰁓𰁂𰁕𰁆𰀁𰁎𰁂𰁏𰁂𰁈𰁆𰁎𰁆𰁏𰁕𰀁𰁑𰁓𰁐𰁈𰁓𰁂𰁎𰀏𰀁𰀳𰁆𰁂𰁍𰀁𰁘𰁐𰁓𰁍𰁅𰀏𰀁𰀸𰁐𰁓𰁍𰁅𰀁𰁄𰁍𰁂𰁔𰁔𰀏𰀁𰀸𰁐𰁓𰁍𰁅𰁘𰁊𰁅𰁆𰀏

𰁘𰁘𰁘𰀏𰁃𰁋𰁔𰁆𰁓𰁗𰁊𰁄𰁆𰁔𰀏𰁄𰁐𰁎

0902off_91 91

2/11/09 3:37:41 PM

FLOWLINES & PIPELINE

Summary of DEH existing projects Project

Asgard Huldra Kristin Norne Tyrihans Ormen Lange

Installation year 2002 Method Reeling Water depth (m) 270 Pipeline length (km) 8.5 Pipeline ID (in) 9 U-value (W/m2K 5 Power demand (mw) 1.4

2002 Reeling 175 16 8 3.6 2

2004 VLS 370 6.8 10 8 1.5

2005 Reeling 380 9 12.6 4 2

2007 S-lay 285 43 to 18 4 10

2006 J-lay <850 20 30 20 6.4

BIM-2

Libreville (~545km)

BIM-3 MAZM-1

BIM-4

Area shown

BIM-1 (B-15) OLM-4

SCM-2

GABON

SCM-1 CMY-1

This project presented a number of unique characteristics which had not been encountered on previous projects in the North Sea including; • Shallow water • Continuous operation (heating in tail-end production) • 60 Hz operation • Reinforced concrete weight coating • Use of anode sledges in Current Transfer Zone. The Olowi DEH system is designed to keep ﬂuid above the WAT (wax appearance temperature) and for reheating after long shutdowns. Olowi Project Water depth (m): 30 - 40 Flowlines number: 3 Pipe length (km): 3.86 - 4.27 Pipe ID (in.): 10.75 U-value (W/m2K): 4.5 Piggyback cable cross-section (sq mm): 1,000 Sea water temperature (° C): 13.5 - 27 Voltage (kV): 1.7 - 2.4 Target temperature (° C): 43 Power demand (MW): 3.0 - 5.0 Temperature maintenance: Target temp (° C): 43 Power demand (mW): 3.0-3.5 Current (A): 1,245 Reheating, remediation: Heat generation (W/m): 133 Current (A): 1,400

Deepwater issues DEH is field-proven to 500 m (1,640 ft) water depth using S-lay since the power cable can piggyback the pipeline on the laying vessel with limited impact on installation. With S-lay, sufficient space can be managed to install an additional work station after the tensioners and before the stinger. Furthermore, the “gentle” V-shaped stinger is suitable for DEH system installation on condition that pipeline position is controlled during the descent form the laying vessel until touchdown point. Where DEH will be needed in deeper waters, J-lay will be required. However J-lay is not as easily adaptable as S-lay method for DEH for the following reasons: 1. There is a unique work station (namely the AST in case of the FDS) on a J-lay vessel, so that any additional required operation at this level will immediately impact the laying rate 2. Deepwater and J-lay installation put additional mechanical constraints on the pipeline and the cable which can be critical given the fragility of the non-armored cable (passage through clamping device, passage through stinger). The field in this offshore West Africa case study has a tie-back of 15 km in water depths from 1,500 m to 2,000 m (4,921 ft to 6,562 ft). The DEH system aims at maintaining the temperature above the 21° C

AFRICA

Olowi

OLGNM-1 (ST-1) OLM-1 (ST-1) NYAM-1

CHRM-1

OLM-1 OLM-6

OLM-5 OLM-3

CTM-1 DLM-1

AWM-1 ARM-1

Olowieea

Themis FABM-1

Atlantic Ocean

Olowi project location and field layout.

(70º F) hydrate formation temperature during shutdowns for a 10-in. ID production flowline and a 4 W/m²/K production flowline U-Value. Based on previous projects, the DEH system is designed to provide about 60W/m to the fluid with a 1,500A supply current and a 3.9kV voltage drop for the 15 km scenario. A 12kV XLPE insulated cable with a conductor cross section of 1,000 sq mm (1.55 sq in) can be used in this case.

J-lay installation Different installation methods have been developed for DEH installation in deepwater. The typical scenario described in the previous section leading to a preliminary designed DEH system for deepwater applications has been used as a reference for this study. The three different installation methods are: 1. “Piggyback”: The attachment of the cable to the pipeline is done on the FDS in the AST. Two possible conﬁgurations are where the cable is normally strapped onto the pipeline and where the cable is inserted into a groove made into the coating 2. Simultaneous installation of the pipeline and the cable (namely dual-laying). The connection of the cable to the pipe can be done subsea by ROV either just after the passage through the stinger or after touch down point 3. Installation of the cable and the pipeline in two separate campaigns: The cable is closed up to the pipe subsea using ROV once the pipe is on the seabed.

Acknowledgements

The authors would like to thank Canadian National Resources International for permission to publish this paper and Saipem Olowi project team for their support on this subject. Editor’s note: This article is a summary of the paper presented at PennWell’s Deep Offshore Technology International Conference & Exhibition 2008 in Perth, Australia. www.offshore-mag.com.

92 Offshore February 2009 • www.offshore-mag.com

0902off_92 92

2/11/09 3:37:42 PM

E Economically effective performance designed to ďŹ t your chemical program needs d

0902off_93 93

2/11/09 3:37:47 PM

EQUIPMENT & ENGINEERING

New tools and technology for the offshore industry Open bore wellhead system key to deep wells in deepwater As offshore wells are drilled in deeper water to deeper depths around the world, the selection of a subsea wellhead system remains a critical factor in meeting the drilling challenges. Drilling operations for these areas will require subsea wellhead systems able to cope with ever-higher pressures, higher temperatures, heavier loads, and an increased number of casing strings. Tried-and-true large bore technology, with an additional structural foundation conductor and an additional string inside of BOP control, remains the equipment of choice for deep wells in deepwater. The large bore wellhead was designed to defeat unconsolidated ocean floor conditions and control shallow water flows both outside and through BOP control. Larger bore holes make it possible to run deeper large-diameter casing strings (16 in. [41 cm]) and 18 in. [46 cm]), which allow the installation of large bore production casing at record-setting depths. The advantage of a variety of casing options, due to low fracture gradients, became clear as soon as deep holes were drilled in the Gulf of Mexico, but adding casing strings inside of BOP control was more troublesome. The industry already had conquered the addition of a 16-in. supplemental casing hanger system inside of 20-in. (51-cm) pipe attached to the bottom of the 18-3/4-in. (48-cm) wellhead. However, adding another casing string such as 18 in. to mitigate the problems associated with shallow water flows and extend a larger diameter wellbore to deeper depths was a tricky problem. The minimum ID of a traditional 18-3/4-in. wellhead is 17-9/16 in. (45 cm) and must sup-

port both the heavy casing weight and the end load from a BOP stack test to be a 15,000 psi rated wellhead system. Thus, to pass an 18-in. casing string through a traditional wellhead would require a new solution. When the minimum ID of the wellhead is opened to pass 18-in. casing and a slightly larger 18-in. casing hanger, the landing shoulder inside the wellhead becomes unusually small in order to support combined casing weight plus the end-load generated from a BOP stack test and still be rated to 15,000 psi. Dril-Quip was the first in the industry to provide a solution, the company says. “For Dril-Quip, the answer was obvious – introduce the same multiple load shoulder profile in the minimum ID to distribute the load over several shoulders that existed in the company’s first generation 18-3/4-in. 15,000 psi subsea wellheads,” says Mike Speer, manager of marketing and training of Dril-Quip. The net result was an 18.510-in. (47-cm) minimum ID. By introducing 22 in. (56-cm) to replace the then-standard 20 in. attached to the bottom of the wellhead, the resulting system was able to maintain the maximum of flow-by required to run and install an 18-in. casing hanger and casing string through an 18-3/4-in. nominal wellhead. In addition, the 18-in. supplemental casing hanger system was designed with a single trip testable seal assembly to seal the annulus between the 22-in. and 18-in. casing strings. Running tools to install all of the BigBore wellhead components have been correspondingly upgraded to carr y the heavier casing loads required in these deep well applications. 

18 3/4 " BigBore wellhead housing

New and tools logy o techn

16" Casing

16" Supplemental casing hanger system

16" Casing

Open bore subsea wellhead system in GoM depth records The first BigBore Wellhead system was installed in 1999. The system has been deployed successfully setting a number of industry records in deepwater and deep well drilling operations in the GoM. • In 2000, Shell installed the system in 7,790 ft (2,374 m) of water • In 2001, BHP Billiton installed the system in 8,835 ft (2,693 m) of water • Shortly thereafter, Unocal set a record with the system in 9,687 ft (2,956 m) of water • By the end of 2001, Unocal again deployed the technology in 9,727 ft (2,965) of water • In 2003, Chevron-Texaco installed the system in 10,011 ft (3,051 m) of water in the Alaminos Canyon in the GoM at a total depth from sea level to the bottom of the hole of over four mi (six km). • In 2008, Murphy Oil spudded a well in the GoM in a record water depth of 10,141 ft (3,091 m) using Dril-Quip’s BigBore II subsea wellhead system.

18" Supplemental casing hanger system

18" Casing

Stack-up of the BigBore II Subsea Wellhead System, depicting a 36 in. x 22 in. x 18 in. x 16 in. x 14 in. x 10-3/4 in. casing program with bull’s-eye level indicators.

94 Offshore February 2009 • www.offshore-mag.com

0902off_94 94

2/11/09 3:36:53 PM

September 1-3, 2009 • New Orleans, LA Hilton New Orleans Riverside OGMT North America is the only conference for maintenance and reliability professionals focusing solely on oil and gas - including upstream, midstream and downstream operations.

OGMT North America is now accepting abstract submittals for the 2009 conference program.

Abstract Deadline: February 16, 2009 Presentations will cover the following topics: • Predictive and Preventive Maintenance

• Maintenance Risk Management

• Fundamentals of Best-in-Class Maintenance

• Maintenance Change Management

• Roadmap to Best-in-Class Maintenance

• Maintenance Benchmarking

• Industrial Maintenance Solutions

• Maintenance Knowledge Management

• Contracting Practices - Outsourcing

• The Need and the Gain on Asset Management

• Aligning Knowledge/Training Towards

• Effective Maintenance KPIs

• Proﬁt Opportunities and Asset Utilization

Performance Excellence

(Key Performance Indicators)

• State-of-the-Art Maintenance Tools & Equipment

• Effective Utilization of CMMS (Computerized Maintenance Management System)

• Maintenance Best Practices

Presentations must be of interest and of practical value to executives, managers and engineers engaged in the petroleum industry. Your abstract should address any of the topics outlined above or any other topic relevant to oil and gas maintenance technology.

For complete abstract submission guidelines, please visit

www.ogmtna.com.

Owned & Produced by:

Please submit a 150-200 word abstract Online

Fax

www.ogmtna.com

Marilyn Radler, Conference Director

(713) 963-6285

Flagship Media Sponsors:

Email: MarilynR@PennWell.com

0902off_95 95

2/11/09 3:36:59 PM

BUSINESS BRIEFS

People Tritech Group has appointed John Smith as technical director. He is responsible for technical research and development throughout the group. Cairn Energy has appointed James Buckee as Smith a non-executive. He will sit on the company’s audit and remuneration committees. Apache’s founder and chairman Raymond Plank has retired. G. Steven Farris succeeds Plank as chairman. Schilling Robotics has appointed David Marchetti as regional operations manager, and Giovanni Escobar as regional sales manager for the company’s Houston office. ARKeX has appointed Stuart Gibson as CFO. The company has also Gibson added Jim Sledzik to its board. BJ Services’ tubular services line has promoted Alan Casson to area manager for the US, Mexico, and Canada. In his new role, Casson is tasked with the continued Sledzik growth of the company’s tubular services division. The company also has appointed Paul Adams as area manager for the Gulf of Mexico with responsibility for overseeing project management, finance, and operations carried out throughout the region; and Greg Braquet has been appointed as operations manager for the Gulf of Mexico with responsibility for overseeing all tubular services operations in the region. Gulf Island Fabrication has appointed Kirk J. Meche as president and COO. Swellfix has appointed Malcolm Pitman as VP. He will manage the company’s operations in Pitman Europe and Russia. Pitman will be based at Swellfix’s headquarters in Aberdeen. GEP has appointed Jean Ropers as president. He succeeds Dominique Michel. Roxar has appointed Serena Arif as regional Arif manager, Europe and Africa for its flow measure-

ment division. Arif will lead Roxar’s growth in Europe and Africa in both sales and services. S & J Diving has appointed Gerald Hart as manager of business development and Chad Wilson as project manager and HSE and OQ development coordinator. The company has also appointed John Joly as senior project coordinator. He will assist with project coordination and business development. Gaffney, Cline & Associates (GCA) has appointed Cesar Emilio Guzzetti as manager for its operations in the Southern Cone of Latin America. Global Industries has appointed Eduardo Borja as senior VP, global marketing and strategy, and John Katok as senior VP, worldwide business development. Borja will be responsible for strategic planning, development, Borja and implementation of the company’s growth strategies including marketing of the company’s services for deepwater applications. Katok will lead Global’s efforts to enhance customer satisfaction by developing processes to improve Katok client sponsorship, project planning, and project execution. Hess Corp. has appointed Greg Hill as president of worldwide exploration and production. Hill will also become an executive VP of the company. He succeeds John O’Connor, who is retiring. BP America has appointed Lamar McKay as chairman and president. He will serve as BP’s chief representative in the US. He succeeds Robert A. (Bob) Malone who has elected to retire after 34 years with the company. Aquanos has appointed Petter Nordby as CEO. The company has also appointed Scott Campbell as GM. Atwood Oceanics has appointed Michael Campbell as VP – controller. Dresser-Rand has appointed Jerry Walker as VP and GM of North America operations. He also assumes responsibility for the company’s Asia-Paciﬁc operations. The company also has appointed Luciano Mozzato as executive VP of product services, Nicoletta Giadrossi as VP and GM for the company’s European operations, and Sammy Antoun as VP and GM of Middle East and North Africa operations. OHM Rock Solid Images has appointed Dr. Arthur Cheng as senior rock physics adviser. He will assist in continuing development of rock physics technology within OHM Rock Solid Images, and will focus on developing

algorithms and mentoring and developing the group’s petrophysical staff. KS Energy Services has appointed Wong Soon Yin as CFO. Wong will oversee the company’s accounting and ﬁnance matters. She replaces Leong Kok Ho. Paul Collins, a non-executive director of BG Group, has retired. Baroness Hogg who was appointed as a non-executive director in 2005, will assume the role of the senior independent director. Siemens Energy Sector’s oil and gas division has appointed Thomas Blades as CEO.

Company News Aker Solutions has entered into an agreement with Total for the additional work on the Frigg decommissioning project. The scope of work has increased beyond the fixed-price contract signed in 2004. Edison Chouest has secured the assignment of Tampa Bay Shipbuilding and Repair’s long-term lease agreement with the Tampa Bay port and has created Tampa Ship LLC. Chouest has assumed management and operation of the yard. Baker Hughes Drilling Fluids has entered into a worldwide marketing agreement with Axiom Process. Under the agreement, Baker Hughes Drilling Fluids and Axiom will jointly develop marketing and sales for the Axiom’s shale shaker and screen products globally, while Baker Hughes Drilling Fluids will exclusively rent the AX-1 shaker and stock screens and spares on a worldwide basis. Edison, the Arab Republic of Egypt, and Egyptian General Petroleum Corp. have signed a concession agreement for Abu Qir fields, granting certain exploration, production, and development rights to Edison. Edison will operate the offshore-Egypt concession jointly with EGPC through a new operating company. The concession has a 20-year duration and can be extended for a further 10 years. BPZ Resources is focusing on an oil development in the offshore block Z-1 in northwest Peru with a goal of doubling production and reserves during 2009. The company plans to commit a majority of its capital expenditures budget to appraise and develop the oil in the Corvina and Albacora fields. BPZ has decided to keep the rig currently drilling at the CX-11 platform in place to drill three additional oil development wells this year. Pritchard Capital Partners and Global Hunter Securities have signed a letter of intent to form Pritchard Global Hunter Securities, a full-service energy-focused investment bank. John Wood Group is sponsoring a professorial chair in arctic engineering at the Memorial University of Newfoundland in St John’s, Canada. CETCO Oilfield Services has signed a deal with the Libyan services agent company, Althuraya Petroleum Services and Sup-

96 Offshore February 2009 • www.offshore-mag.com

0902off_96 96

2/11/09 3:37:50 PM

BUSINESS BRIEFS

plies, to provide water treatment services to the Libyan oil and gas industry. Neptune Marine Services has acquired Subsea Engineering Services, a provider of subsea consultancy and project services to the oil and gas industry. SLP Engineering has awarded Mech-Tool Engineering a contract to supply stainless steel external fire wall cladding for a new living quarters platform, as part of BP Norge’s Valhall field re-development. Hallin Marine has formed a robotics division called Hallin Robotics. According to Hallin, the new company will exploit decommissioning opportunities for both the nuclear and offshore industry and build upon the group’s existing contracts using its robotics expertise in design and operation. The non-operating partners of the Huntington field in the UK have unanimously decided to remove Oilexco as operator of the license and accept E.ON Ruhrgas as the new operator. Oilexco will now serve as a non-operating partner in the license. BJ Services has opened a new pipeline inspection facility in Houston, Texas. The 20,000-sq ft (1,858-sq m) facility will provide strategic operations and data analysis for all of the company’s pipeline inspection operations throughout the US. NACE International has opened its new international training center. According to NACE, the $2.4 million facility is the nation’s first freestanding training center dedicated exclusively to advancing corrosion education. ATR Group has sold the business and assets of ATR Hydraulics to Hydrasun.The deal has led to the formation of a strategic alliance between ATR Group and Hydrasun, which will provide customers with more choice and an enhanced range of services and capabilities regarding hydraulics, fluid transfer systems, and tool and equipment rental services, the companies say. Antrim Energy has submitted a field development plan for Phase I of the Causeway field to the UK Department of Energy and Climate Change. The FDP, which plans production through a subsea tieback to the Dunlin platform, is for the eastern area of the Causeway field only, and is the first phase of what is anticipated to be several phases of development of the field. BPZ Resources and Shell Exploration have mutually agreed to discontinue discussions on the farm-out agreement as conceptualized in a non-binding Memorandum of Understanding. BPZ Energy will maintain its 100% working interest in blocks Z-1, XIX, and XXIII, as well as block XXII which was not part of the proposed transaction, all of which are located offshore Peru. Boots & Coots International Well Control has renewed its Safeguard contract with the Oil and Natural Gas Corp. of India

for an additional five years. The contract is for training, inspection, and blowout control for ONGC’s 28 offshore rigs and 94 land rigs. Cameron has acquired Precision Downhole Pumps, a US-based manufacturer of artificial lift equipment. Precision, based in Iola, Kansas, will be integrated into the surface systems division of Cameron’s drilling and production systems group based in Houston. Signa Engineering has acquired Fisk/ MEI Inspection Services, an inspection and expediting services company for oilfield equipment and tubulars. Fisk is now a wholly owned subsidiary of Signa Engineering, with Robert G. “Bob” Davis serving as president and CEO. BRGM and IFP have signed a research partnership agreement for the development of software tools dedicated to the study, dimensioning, and monitoring of geological CO2 storage facilities. PetroVietnam, the national oil company of Vietnam, has approved the application for two appraisal areas within block 16-1, according to the Hoang Long Joint Operating Co. The company, which is the operator of block 16-1 in the Cuu Long basin offshore Vietnam, will now submit the documentation required for the formal governmental approval. Centek and a major US oilfield services and products supplier have signed a three year, worldwide agreement for the supply of casing centralizers. The agreement covers the entire Centek centralizer and stop collar range, primarily for use in extended reach, highly deviated, and underreamed wells. Triton Group has acquired Houston-based Equipment & Technical Services. ETS develops, rents, and sells equipment and software for offshore survey and marine applications. Halliburton has entered into an agreement with Derrick Equipment to expand Baroid Fluid Services’ offering of solids control equipment and services. Derrick Equipment will serve as the exclusive supplier of its full range of products, including shale shakers, centrifuges, and screens to Baroid. Mariner Energy has purchased an additional 11.6% working interest in the Bass Lite natural gas field (Atwater Valley block 426) from Energy Resource Technology for approximately $32.6 million. Oando Exploration and Production has acquired 75% interest in Exile Resources’ 40% working interest in the Akepo field offshore Nigeria. Oilexco North Sea intends to file petitions for administration in the High Court in the UK. OceanWorks International has relocated to a new facility in Burnaby, British Columbia. The facility houses an indoor freshwater test tank, pressure test facility, machine shop, ESD safe electrical assembly area, high voltage test laboratory, a large vehicle assembly area, and

includes over 5,000 sq ft (465 sq m) of excess warehouse for storage and future expansion. PTT Exploration and Production Public, through its wholly owned Australian subsidiary, has signed a conditional share sales agreement to acquire a 100% equity interest in Coogee Resources for $170 million. FMC Technologies has acquired a 45% interest in Schilling Robotics for $116 million. The company is also acquiring the rights to exercise an option over the two-year period beginning in 2012 to acquire the remaining 55% of the company. Mediterranean Oil & Gas has submitted its application to the Italian Ministry of Economic Development for an offshore production concession over the Ombrina Mare ﬁeld offshore Italy. StatoilHydro has exercised the Phase 3 option for modiﬁcation of the Statfjord B&C topsides with Aker Solutions. The option represents a continuation of the Statfjord Latelife project currently executed by Aker Solutions. TAQA Bratani has awarded Subsea 7 a one-year inspection, repair, and maintenance services agreement for the provision of project management, engineering, dive support, and remote intervention services to assist with TAQA’s newly acquired northern North Sea assets. Otto Energy has entered into a conditional heads of agreement with BHP Billiton Petroleum to farm out 60% of its interest in Service Contract (SC) 55. SC55 covers a deepwater block located offshore southwest Palawan Island, in the Philippines.

Rig market adjusts ... continued from page 36

The demand for jackups in the region might see a small rise mid-year, but should return to current levels by the end of 2009. That said, supply already is ahead of demand now and the surplus will grow during the year unless freshly delivered jackups pick up contracts and move out of the area. Semi demand in the region will climb some over the period, while supply will experience only a modest rise, leading to a minor deﬁcit. Little if any change is anticipated in the drillship market in the Asia/Paciﬁc region. Day rates for jackups in the region have stayed about the same over the last 12 months, aside from small growth in Australia and New Zealand, and range from about $130,000 to $252,000. The range of rates that semis are earning has also been stagnant between $143,500/day and $550,000/day. However, a year ago drillships were earning a maximum day rate of about $285,000, but now they are ranging from $245,000 to $640,000. 

www.offshore-mag.com • February 2009 Offshore 97

0902off_97 97

2/11/09 3:37:52 PM

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

• Display Ads: $215.00 per column inch. Same discount as above. 15% agency commission. $200.00 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) 831-9776. E-mail: glendah@pennwell.com • No special position available in classiﬁed.

C ON SU LTA N T S

E MP LOY ME N T

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: contato@expetro.com.br Web: www.expetro.com.br -Rio de Janeiro, Brazil

THE ENERGY INDUSTRY’S MOST POWERFUL JOB BOARD

P I P E L IN E L OC ATOR PIPELINE LOCATOR / COORDINATE MAPPING DEVICE USPTO PATENT NO.(s): 20050076724 & 20060254373

LICENSE – DEVELOP – UTILIZE

Generate 3-D As-Built Survey Plat Plans from Data Analysis (Reference 49CFR192.927.c.1.ii & ASME B31.8S,P6.4.2) Contact: Todd G. Boudreaux, P.E. Email: tgboudreaux@yahoo.com

Post. Search. Work! PennEnergyJOBS is a full-service recruitment advertising solution: • • • • •

job postings resume search print classiﬁeds banner advertising newsletter sponsorships

• targeted email campaigns • web broadcasts • career fairs

Call our dedicated recruitment advertising team today! Our customized solutions can help lower your cost per hire and time to hire. Ask us how! (800) 331-4463 or sales@PennEnergyJobs.com

Turning Information into innovation Serving Strategic Markets Worldwide since 1910

Hiring? Selling Equipment? Need Equipment? CONTACT: GLENDA HARP

+1-918-832-9301 or 1-800-331-4463, Ext. 6301 Fax: +1-918-831-9776 Email: glendah@pennwell.com 98 Offshore February 2009 • www.offshore-mag.com

0902off_98 98

2/11/09 3:37:32 PM

ADVERTISERS INDEX A

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) davidd@pennwell.com Bailey Simpson (Regional Sales Manager) baileys@pennwell.com Mona El-Khelaly (Advertising Services) monaek@pennwell.com Glenda Harp (Classified Sales) glendah@pennwell.com GREATER HOUSTON AREA, TX David Davis davidd@pennwell.com USA • CANADA Bailey Simpson baileys@pennwell.com SCANDINAVIA •THE NETHERLANDS • MIDDLE EAST 11 Avenue du Marechal Leclerc 61320 Carrouges, France PHONE +33 2332 82584 • FAX +33 2332 74491 David Betham-Rogers davidbr@pennwell.com UNITED KINGDOM PennWell Corporation Warlies Park House, Horseshoe Hill, Upshire Essex, United Kingdom EN9 3SR PHONE +44 (0) 1992 656 665 • FAX +44 (0) 1992 656 700 Linda Fransson lindaf@pennwell.com FRANCE • BELGIUM • PORTUGAL • SPAIN • SOUTH SWITZERLAND • MONACO • NORTH AFRICA Prominter 8 allée des Hérons, 78400 Chatou, France PHONE +33 (0) 1 3071 1224 • FAX +33 (0) 1 3071 1119 Daniel Bernard danielb@pennwell.com 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 wilhelms@pennwell.com ITALY UNIWORLD MARKETING Via Sorio 47 - 35141 Padova, Italy PHONE +39 (04) 972 3548 • FAX +39 (04) 985 60792 Vittorio Rossi Prudente vrossiprudente@hotmail.com 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 ogjbrasil@ogjbrasil.com.br, Url www@pennwell.com.br Marcia Fialho marcia.fialho@pennwell.com.br JAPAN e. x. press Co., Ltd. Hirakawacho TEC Bldg., 2-11-11,Hirakawa-cho Chiyoda-Ku, Tokyo 102-0093, Japan PHONE +81 3 3556 1575 • FAX +81 3 3556 1576 Manami Konishi manami.konishi@ex-press.jp SINGAPORE 19 Tanglin Road #09-07 Tanglin Shopping Center Singapore 247909 PHONE +65 6 737 2356 • FAX +65 6 734 0655 Michael Yee yfyee@singnet.com.sg INDIA Interads Ltd., A-113, Shivalik, New Delhi 110 017 PHONE +91 11 628 3018 • FAX +91 11 622 8928 Rajan Sharma rajan@interadsindia.com 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 q-she@inbox.com

0902off_99 99

Acergy.........................................................48a-b www.acergy-group.com

Lincoln Electric.. ............................................. 37

Acteon............................................................. 2-3 www.acteon.com Aker Solutions.. .............................................. 19

LTI Drilling.. ..................................................... 36 www.letourneautechnologies.com

Alcoa Oil & Gas............................................... 11 www.alcoaoilandgas.com Allegheny Technologies.. ............................... 47 www.AlleghenyTechnologies.com API (American Petroleum Institute)............... 76 www.api.org

B Baker Hughes Incorporated INTEQ.......................................................... 81 AnswersWhileDrilling.com/AutoTrak Bell Helicopter ................................................ 67 bellhelicopter.com Bisso Marine. .................................................. 40 www.bissomarine.com BJ Services. .................................................... 91 www.bjservices.com Bredero Shaw. ................................................. 15 www.shawcor.com Bupa International. ......................................... 34 www.bupa-intl.com

C Cameron .......................................................... 23 www.c-a-m.com/camforce CapRock Communications .............................. 5 www.CapRock.com CD-Adapco ...................................................... 86 www.cd-adapco.com Clifford-Jacobs Forging ................................... 6 www.clifford-jacobs.com Clover Tool Co.. ............................................... 54 www.clovertool.com CRC-Evans Automatic Welding. .................... 53 www.crc-evans.com Cudd Energy Services ................................... 55 www.cudd.com

D DEVIN International....... ................................. 33 www.devindevin.com Dow Hyperlast....... .......................................... 50 www.dowhyperlast.com Dresser, Inc...................................................... 26 www.dresser.com

F Fairfield Industries, Inc................................... 31 fairﬁeld.com Fluor Corporation...... ..................................... 39 www.ﬂour.com/offshore FMCTI ..............................................................C2 www.fmctechnologies.com Frank Mohn Flatoy AS...... .............................. 27 www.framo.com Fugro................................................................ 43 www.fugro.com

G GE Energy........................................................C3 www.ge-energy.com/oilﬁeld www.sondex.com

H Halliburton Energy Services .......................... 21 www.halliburton.com/adr

I IES SRL............................................................ 65 www.omc.it

J John M. Campbell & Co.................................. 34 www.jmcampbell.com/OSM

K Karmsund Maritime Offshore Supply AS.. ... 52 www.karmsund.no KnightHawk Engineering.. ............................. 16 www.knighthawk.com

M Magnetrol International .................................. 63 magnetrol.com Modular Reel AS ............................................. 85 www.m-reel.com Multi-Chem ...................................................... 93 www.multichem.com/safespend Mustang Engineering .......................... 75, 77, 79 www.mustangeng.com

N National Oilwell Varco ..................... 7, 29, 41, 51 www.nov.com

O Orion Instruments .......................................... 69 orioninstruments.com ORR Safety Corporation ................................ 59 www.orrsafety.com/kong

P Parker Hannifin Corporation .......................... 25 www.parker.com PennEnergy ..................................................... 49 www.pennenergy.com PennWell MAPSearch ................................................. 72 www.mapsearch.com OGMT North America ................................ 95 www.ogmtna.com Offshore Asia ........................................... ..73 www.offshoreasiaevent.com Subsea Tieback Forum & Exhibition ........ 87 www.subseatiebackforum.com Perry Equipment Corporation ....................... 13 www.pecofacet.com Proserv Offshore............................................. 60 www.proserv-offshore.com

Q Qatar Airways .................................................. 35 qatarairways.com

R R.M. Young Company ..................................... 85 www.youngusa.com

S Schlumberger ................................................. 61 www.slb.com/xlift Schlumberger .................................................C4 www.slb.com/stethoscope Shanghai Zhenhua Port Machinery Co., Ltd...... .............................................................. 57 www.zpmc.com SPE - 2009 Digital Energy Conference and Exhibition ........................................................ 78 www.digitalenergy2009.com SPE - 2009 Offshore Technology Conference.... .................................................. 83 www.otcnet.org/2009 SPT Energy Group .......................................... 14 www.spt-energy.com

T Transocean.. ...................................................... 1 www.deepwater.com

V Versabar, Inc.................................................... 17 www.vbar.com

W Wavefield Inseis ASA...................................... 45 www.waveﬁeld-inseis.com Weatherford International ................................ 9 www.weatherford.com WPT Power Transmission Corporation ......... 16 www.WPTpower.com

The index of page numbers is provided as a service. The publisher does not assume any liability for error or omission.

2/11/09 3:37:36 PM

BEYOND THE HORIZON

Finding innovation outside the oil and gas industry Today’s deepwater ater discoveries are impressive in size and scope. Developing these finds requires ongoing technological advances in many areas including geology, geophysics, drilling, production, subsea processing, intervention, and environmental remediation to name only a few. Much of the required innovation will come from within the petroleum industry. Nonetheless, there are compelling reasons why the petroleum industry should also look externally to the many small and mid-sized companies operating in other industries. These smaller enterprises often have limited public exposure and are overlooked easily, yet they are havens of technological progress. Backed by funding from angel investors, venture capital funds, and other sources, these young companies quietly generate promising breakthroughs. The extent of this funding varies; but it is not unusual for an early-stage company to consume $5 million, $10 million, or even more before producing commercial products. By reaching out to these nascent companies, the petroleum industry can leverage the substantial risk capital provided by other sources. Furthermore, if serial number 001 of the technology is being tested or used in another industry, this helps to overcome the early adopter reluctance sometimes encountered in the offshore petroleum industry. For example, advances in electronics are allowing the suitcasesized Electron Spin Resonance spectrometer to be miniaturized and converted into a diagnostic device similar in size to a hockey puck. This compact instrument can continuously monitor lubricating fluids in offshore compressors or other rotating equipment to detect the imminent breakdown of those lubricants. There are strong indications this same technology can be incorporated in subsea flowlines to detect the real-time formation of hydrates at even parts per million concentrations. In another instance, a small venture funded company is marketing a new class of electro-resistive coatings. These advanced coatings display several order of magnitude improvements in electrical resistivity compared with existing technology. The coatings are a few thousandths of an inch thick and can be applied to flat, cylindrical, or irregularly shaped surfaces on metals, some ceramics, glass, and certain polymers. This company is investigating subsea pipeline and seabed wellhead applications for this breakthrough heating material. An early stage company in the materials arena is applying a unique

nano and micro lamination process to produce interleaved metal alloys, refractory metals, ceramics, and composites. Each layer literally is grown in place via a cost-effective, room temperature deposition process. The resulting material is analogous to metal “plywood” with hundreds of thousands of individual metal “plys”. Products made via this process exhibit crack and corrosion resistance under high-pressure/ high-temperature conditions. They also have other valuable properties consistent with offshore, subsea, and deep well applications. A small company associated with the manufacturing industry has developed a search engine for digitized 3D content. The software can recognize fine details and identify similar 3D representations even if the 3D files have different orientations in the database. Initial applications are in complex manufacturing activities involving large databases, as a cost savings and supply chain management tool. This same software also may have offshore exploration and production applications. The company’s automated shape encoder is independent of the shape file format. Consequently, a 3D seismic database is encoded in the same manner as a database of mechanical components. This means the software may be capable of real-time searches for comparable shapes in seismic datasets or other petroleum industry databases containing 3D subsurface information. A long-life power source for seabed seismic nodes, autonomous underwater vehicles, and other deepwater applications is nearing commercialization by a California-based company. The development process has taken over a decade and has required substantial funding from the U.S. military and other sources, but the resulting lithium-seawater battery boasts impressive power densities. It weighs less than other offshore battery chemistries, is able to withstand pressures up to 10,000 psi and discharges uniformly for over a year without maintenance. These and many other technologies have cross-over applications in the offshore petroleum industry. Locating the companies developing these breakthroughs requires a degree of effort; however the potential benefits to the offshore industry are substantial.

John C. Barratt

Oil & Gas Innovation Center

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 Eldon Ball at eldonb@pennwell.com.

100 Offshore February 2009 • www.offshore-mag.com

0902off_100 100

2/11/09 3:37:53 PM

GE Energy

Fuel Your Growth. You and GE’s Oilfield Technology: Together, we can make it happen. With our powerful and expanding Oilfield Technology portfolio, GE Energy is an ideal partner for growing service companies. Our high performing Drilling Measurement and Sondex Wireline products help companies like yours provide new services, develop new markets and operate in harsher environments. Our team can also help you lower your operational costs—with hands-on training and real-time support. Just as importantly, our experience and expertise allow us to respond quickly to changes in your markets so you don’t miss emerging opportunities. For more information about GE’s Oilfield Technology offerings, visit our website at www.ge-energy.com/oilfield or www.sondex.com. If you’re ready to expand your horizons, let us help fuel the way.

0902off_C3 C3

2/11/09 2:00:20 PM

StethoScope FORMATION PRESSURE WHILE DRILLING

*Mark of Schlumberger. Welcome to productive drilling and Measurable Impact are marks of Schlumberger. ÂŠ 2009 Schlumberger. 09-DR-0049

Productive Under Pressure

Welcome to productive drilling. An operator using the StethoScope* service increased recoverable reserves in a North Sea well approximately 15% by optimizing well placement in oil-filled channel sands. Pressure, psi 6,000 6,500 7,000 7,500 7,560 7,600 3,600 3,750

StethoScope formation pressure-while-drilling service sends more real-time data and quality indicators to surface faster with Q

accurate, quality-controlled measurements

automatic maximum bandwidth

no tool orientation.

www.slb.com/stethoscope

Global Expertise Innovative Technology Measurable Impact

4,000 4,500 5,000

0902off_C4 C4

2/11/09 2:00:22 PM

ASIA

Beibu production issues In Beibu Gulf Block 22/12, covering an area of 342 sq km (132 sq mi), ROC Oil is op-

The newly on stream Zhao Dong ODB platform with drilling rig alongside.

64 Offshore February 2009 • www.offshore-mag.com

0902off_64 64

2/11/09 2:55:32 PM

0902off_65 65

2/11/09 2:55:35 PM

GEOLOGY & GEOPHYSICS

BPC re-assessing potential of southern Bahamas play Jeremy Beckman

Editor, Europe

BPC’s licenses offshore the Bahamas, including prospects.

66 Offshore February 2009 • www.offshore-mag.com

0902off_66 66

2/11/09 3:28:17 PM

0902off_67 67

bellhelicopter.com b l be 1-800-FLY-BELL

2/11/09 3:28:24 PM

GEOLOGY & GEOPHYSICS

Map shows drilling locations for BPC’s well and core data base.

68 Offshore February 2009 • www.offshore-mag.com

0902off_68 68

2/11/09 3:28:26 PM

LIQUID LEVEL MEASUREMENT

When the going gets tough, the tough get an Orion. Orion level gauges take on the toughest measurement challenges in the world’s harshest conditions.

rion level controls are built tough. Our Aurora Magnetic Level Indicator (MLI) combines float-

AURORA®

Float-based level indicator with a redundant Guided Wave Radar transmitter

ATLAS™

Float-based Magnetic Level Indicator (MLI)

JUPITER® Float-based Magnetostrictive level transmitter shown mounted to an Atlas MLI

liquid level indication at orioninstruments.com. • Onshore/Offshore Oil & Gas

• Oil and Gas Refining

• Thermal & Nuclear Power

• Water & Wastewater

• Pharmaceutical & Biotech

• Chemical Processing

6646 Complex Drive • Baton Rouge, LA 70809 • 1-866-556-7466 • info@orioninstruments.com

0902off_69 69

2/11/09 3:28:28 PM

GEOLOGY & GEOPHYSICS

J. van Gestel K.D. Best O.I. Barkved J.H. Kommedal

BP Norway

ity and well failures, and to improve the geomechanics model.

Reservior model

Seismic data

Seismic modeling software

Processing

Synthetic seismic volumes Time-lapse analysis

Seismic volumes Calculation from initial thickness, initial porosity and pore volume multipliers

Time-lapse analysis

Difference volumes

Time shift volumes

Extraction

Map with observed seismic changes

Map with observed time shifts

Map with predicted seismic changes

Match quality factor

Equation using R=5.7 Map with predicted compaction maps

Match quality factor

Map with observed compaction

70 Offshore February 2009 • www.offshore-mag.com

0902off_70 70

2/11/09 3:28:29 PM

GEOLOGY & GEOPHYSICS

0902off_71 71

2/11/09 3:28:29 PM

GEOLOGY & GEOPHYSICS

Acknowledgements

MAPSearch MAPS A PennWell Company

For more information form please ase revi review our product offerings at www.mapsearch.com ch o tac us directly at 800-823-6277. or contact

0902off_72 72

2/11/09 3:28:31 PM

DRILLING & COMPLETION

Al Shaheen field, offshore Qatar.

David Brink Barry Gabourie Morten Hesselager Pedersen

Maersk Oil Qatar AS

M. Rushdan Jaafar

Qatar Petroleum

Junction selection After reviewing various multi-lateral options, it was concluded that Technical Ad-

Completion design Reservoir control is important for both production and injection wells in the current development plan, so individual control of each lateral was

74 Offshore February 2009 • www.offshore-mag.com

0902off_74 74

2/11/09 3:28:37 PM

DRILLING & COMPLETION

Front End Experienced Teams ready for your next project. • Field Development • Concept and Feasibility Studies • FEED • Cost Estimates

People Oriented... Project Driven®

Houston • London • Perth • Mumbai www.mustangeng.com Typical completion configuration for a multi-lateral well. www.offshore-mag.com • February 2009 Offshore 75

0902off_75 75

2/11/09 3:28:39 PM

DRILLING & COMPLETION

Project Execution Experienced Teams ready for your next project. • Engineering Design • Construction Management • Project Management • Commissioning Support

People Oriented... Project Driven®

Houston • London • Perth • Mumbai www.mustangeng.com

www.offshore-mag.com • February 2009 Offshore 77

0902off_77 77

2/11/09 3:28:41 PM

DRILLING & COMPLETION

People Oriented... Project Driven®

Acknowledgement

The authors thank the management of Qatar Petroleum and Maersk Oil Qatar AS for their encouragement and permission to publish this work.

Editor’s note: This article is a summary of the paper presented at PennWell’s Offshore Middle East Conference & Exhibition 2008 in Doha, Qatar. www. offshore-mag.com.

Houston • London • Perth • Mumbai www.mustangeng.com

www.offshore-mag.com • February 2009 Offshore 79

0902off_79 79

2/11/09 3:28:44 PM

DRILLING & COMPLETION

Despite equipment limitations in the region, India’s Jindal Drilling steps forward Chairman D D.P. P Jindal outlines strategy for new technologies Gurdip Singh

Contributing Editor

Jindal took delivery of jackup Virtue I from Keppel FELS in December for a five-year contract with ONGC.

80 Offshore February 2009 • www.offshore-mag.com

0902off_80 80

2/11/09 3:28:46 PM

Extended Reach. Precise Placement. Objective:

Geosteer highly complex, extended reach, lateral branch along ultra-thin oil column to 7,230 m (23,720 ft), including ﬂat 135° azimuth turn at horizontal, precisely navigating relative to the oil-water contact.