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E P M A G . C O M
ExtendingReservoir Life
Marine Seismic
Deepwater RigAdvances
Sand/WaterManagement
RiserTechnology
A Y 2 0 1 2
DEEPWATER renaissance
Offshore activity flourishes
2012 Meritorious
EngineeringAwards
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Visit Booth 5633 for a new perspectiveRobbins & Myers Energy Services Group is mee t ing globa lcus tomer demand fo r b r e a k t h r o u g h t e c h n o lo g y, e n h a n c e dsafe ty and improved service f r o m explorat ion to t r ansmiss ion .www. r me n e rgy. com
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136 2012 MERITORIOUSENGINEERING AWARDS
EXTENDING RESERVOIR LIFE
EOR system creates seismic shift in waterfloodtechnology
Reservoir modeling extends field life
Enhancing asset performance should notcompromise safety
ADVANCES IN MARINE SEISMIC
Broadband acquisition a step-change fordeepwater imaging
Marine seismic acquisition gets improvements
DEEPWATER DRILLING ADVANCES
Uniform designs win out in ultra-deepwateractivity
RFID technology optimizes riser asset tracking,maintenance
SAND/WATER MANAGEMENT
Managing sand through flow control in themodern completion
WEA technique saves time, money
RISER TECHNOLOGY
Connectors stiffen Caesar Tongas resolve
Brazilian E&P spending fuels major supplyvessel growth
SPECIAL REPORT: CASPIAN REGION
Two sides of the same sea
REGIONAL REPORT: GULF OF MEXICO
Mexico to realize its deep potential
IndustryPULSE:US upstream promisesopportunitiesA new report shows US production and optimism on the rise.
EXPLORATION & PRODUCTIONW O R L D W I D E C O V E R A G E
MAY 20 12VOLUME 85 ISSUE 5
A HART ENERGY PUBLICATION www.EPmag.com
34
As oil and gas companies push the limits in terms ofwater depths and remote locations, the challenge ofdeveloping technologies and practices that can lowerhuge upfront costs is being met collaboratively throughjoint industry initiatives and technology partnershipsaround the world.
Riser gas risk mitigation ona drillship uses closed-loopcirculation drilling systems
Longer,deeper,colder
8
WorldVIEW:Finding the next big thingThe recipe for a successful geoscientist?Travel the world and ask a lot of questions.
12
Unconventional:International ShalesShale gas is poised to becomeinternational phenomenon
Overcoming obstacles to develop vast unconven-
tional resources across the globe will be crucial tomeet rising energy demands.
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COVER STORY: DEEPWATER CHALLENGES & SOLUTIONS
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AS I SEE ITDrumroll, please! 5
MANAGEMENT REPORTAsset management services provide modular solutions offshore 16
DIGITAL OIL FIELDIntegrated operations platform overcomes production challenges 22Digital automation solution enhances oil recovery in the Caspian Sea 25
EXPLORATION TECHNOLOGYDoes the US government need a lesson in economics? 29
WELL CONSTRUCTIONPerformance is a shared benefit 31
PRODUCTION OPTIMIZATIONTurning fast talk into fast results 33
TECH WATCHNew tool gathers downhole pressure and temperaturedata while fracturing horizontal wells 122
TECH TRENDS 126
INTERNATIONAL SPOTLIGHT: NEW ZEALAND 129
INTERNATIONAL HIGHLIGHTS 146
ON THE MOVE/INDEX TO ADVERTISERS 150-151
LAST WORDDeep water is the fastest growing offshore sector 152
E&P (ISSN 1527-4063) (PM40036185) is published monthly by Hart Energy Publishing, LP, 1616 S. Voss Road, Suite 1000, Houston,Texas 77057. Periodicals postage paid at Houston, TX, and additional mailing offices. Subscription rates: 1 year (12 issues), US $149;2 years (24 issues), US $279. Single copies are US $18 (prepayment required). Advertising rates furnished upon request.POSTMASTER:Send address changes to E&P, PO Box 5020, Brentwood, TN 37024. Address all non-subscriber correspondence to E&P, 1616 S. VossRoad, Suite 1000, Houston, Texas 77057; Telephone: 713-260-6442. All subscriber inquiries should be addressed to E&P, 1616S. Voss Road, Suite 1000, Houston, TX 77057; Telephone: 713-260-6442 Fax: 713-840-1449; [email protected]. Copyright Hart Energy Publishing, LP, 2012. Hart Energy Publishing, LP reserves all rights to editorial matter in this magazine. No article may bereproduced or transmitted in whole or in parts by any means without written permission of the publisher, excepting that permission tophotocopy is granted to users registered with Copyright Clearance Center/0164-8322/91 $3/$2. Indexed by Applied Science, TechnologyIndex and Engineering Index Inc. Federal copyright law prohibits unauthorized reproduction by any means and imposes fines of up to$25,000 for violations. RIDEALONG ENCLOSED.
DEPARTMENTS AND COMMENTARY
ABOUT THE COVER Pictured is ENSCO 8505 , now undergoing sea trials inthe Gulf of Mexico. The rig was mobilized from the Keppel Fels shipyard inSingapore in just 39 days. As part of a rig-sharing agreement, the vessel will bedrilling for Anadarko, Noble Energy, and Apache later this year. On the left, righands on the Deepwater Millennium drillship prepare for drillstem testing forAnadarko Petroleum on the Barquentine 2 well offshore Mozambique. (Photoscourtesy of Ensco and Anadarko Petroleum; cover design by Laura J. Williams)
COMING NEXT MONTH The June issue of E&P examines the growing and increasinglycomplex world of downhole tools and systems as well as unconventional resource development.Other features focus on logging and formation evaluation, directional drilling, testing and productionmanagement, and advances in mooring systems, and regional highlights include the Mississippi Limeformation in Oklahoma and Kansas and the hotbed of activity that is South America. As always, whileyoure waiting for the next copy of E&P , remember to visit EPmag.com for news, industry updates, andunique industry analysis.
Printed onrecycled paper
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Meeting the challenges of ourcus tomer s has always beenthe focus of our work , and itcontinues to be the measureof our success today.
The relationships we buildwith operators h a v e helped
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Our c o l l a b o r a t i v ea p p r o a c hhas generated a number oftechnical innovations to meetthe changing needs of ourcustomers such as exploitingunconventional resources anddefining industry best practice.
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ONLINE CONTENT MAY 2012
PREMIUM CONTENT Subscribe @ EPmag.com/explorationhighlights
AVAILABLE ONLY ONLINE
Deep water pushes market upfor offshore service vesselsBy Scott Weeden, Senior Online Editor
With a fleet of offshore vessels with anaverage age of 5.6 years, Bourbon ispoised to tap into the increasing marketsfor deepwater and shallow-water vessels.
Service companies benefitfrom industry recoveryBy Oil & Gas Investor staff Oil and Gas Investor asked service and
supply analysts to detail the sectors mainthemes and describe what will benefit thecompanies most in 2012.
True or false? Your unconventionalresources IQ is being testedBy Mike Madere, Senior Online Editor
Whether unconventional resources arein Poland, France, China, or the US, thetechnology to develop those resources ishighly sought after in todays market.
Offshore Namibia block has mean estimate of 3.17 BbblA prospective report prepared for EnerGulf Resources for four off-shore Namibia prospects and nine leads on Block 1711 shows amean estimate of 3.17 Bbbl of potentially recoverable oil, accordingto Oil & Gas International.
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Alberta Bakken discovery reported on Lethbridge propertyA Dee Three Exploration Ltd. Bakken well flowed 550 bbl of 30API oiland 60,000 cf/d of gas.
Apache: Green Canyon prospectcould have up to seven wildcatsApache Corp. filed an exploration plan todrill up to seven wildcats on a two-blockprospect in the Green Canyon area inapproximately 1,250 m (4,100 ft) waterdepth. The first proposed exploratory testwill be in the southern portion of GreenCanyon Block 823 (OCS G33854), with a proposed bottomhole to thesouth beneath Block 867 (OCS G33858).
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I somewhat hesitantly step onto this page of E&P as its new executive edi-tor after remembering some of my predecessors feedback. One of oureditors (who shall remain nameless) was so reviled by our managing editorthat she blew up his As I see it photo and thumbtacked it to her bulletin
board such that the thumbtacks looked like devil horns. Another editor, Bill Pike, once received an e-mail reading, Dear Bill: As I
see it, youre a moron.So as I prepare myself for target practice, I would like to direct your
attention to our special feature on the Meritorious Awards for EngineeringInnovation (MEAs). This years winners join an august group of ground-breaking technologies that date back to 1971. (The complete list will beposted to our website once I find out who won in 1999!)
These highly coveted awards are judged by a panel of experts culled fromindustry, academia, and consultants. Judges are asked to rate each entry interms of its innovation in concept, design, and application; its ability tohelp solve a costly problem; and its potential to improve efficiency or prof-
itability.Out of almost 70 entries our judges chose 13 winners and four honorable
mentions. The specifics on each of these entries can be found further backin this issue. Winners will be honored at this years Offshore Technology Conference and at Hart Energys Developing Unconventional Oil confer-ence in Denver, Colo., May 14-16.
While were on the subject of the MEAs, I would like to encourage any-one who develops technology to consider entering the 2013 contest. Enter-ing is simple:
1. Visit Epmag.com/mea/mea.process.php .2. Create an account, or enter your personal entry page if you already
have an account.
3. Submit an abstract, case study, and up to three supporting documentsfor each entry.
This years deadline is Dec. 31. Weve added new categories to accommodate more entries in the subsea,
deepwater, and Arctic technology arenas, and we welcome those entries as well as our standard entries for drilling fluids, exploration technology, etc.
Enter early and often, and good luck!Finally, I would like to thank Dick Ghiselin, head of our editorial advisory
board, and Richard Mason, our executive editor online, for filling this page while we sorted some things out internally. Well aim for a bit more consis-tency from now on, and Ill keep my bullet-proof vest close by.
As ISEE IT
1616 S. VOSS ROAD, STE 1000HOUSTON, TEXAS 77057
P: +1 713.260.6400 F: +1 713.840.0923www.EPmag.com
Drumroll, please!
7
Read more commentary atEPmag.com
RHONDA DUEY
Executive [email protected]
Executive Editor RHONDA DUEY
Senior Editor TAYVIS DUNNAHOE Senior Editor SCOTT WEEDEN
International Editor MARK THOMAS
Associate Editor NANCY AGIN
Assistant Editor CODY ZCAN
Corporate Art Director ALEXA SANDERS
Senior Graphic Designer LAURA J. WILLIAMS
Production Director& Reprint Sales JO LYNNE POOL
Editorial Director PEGGY WILLIAMS
Chief Technical Director, Upstream RICHARD MASON
Director of Business Development ERIC ROTH
Senior Editor/Manager,Special Projects JO ANN DAVY
Group Publisher RUSSELL LAAS
Editorial Advisory Board
CHRIS BARTONSr. VP Business Development, Oil & Gas., KBR
KEVIN BRADYVP, Sales & Marketing,Verdande Technology Inc.
MIKE FORRESTExploration Consultant, formerly with Shell
JOHN M. GILMORE JR.Director of Global Industry Solutions Upstream
Oil & Gas, Invensys Operations ManagementCHRIS JOHNSTON
VP & Managing Director, North America, EnscoULISSES T. MELLO
Manager, Petroleum & Energy Analytics, IBMDONALD PAUL
Executive Director, University ofSouthern California Energy Institute
EVE SPRUNTBusiness Development Manager,Chevron Energy Technology Co.
MANUEL TERRANOVASr. VP Regional Operations & Global Sales,
Drilling & Production, GE Oil & GasRONNIE WITHERSPOON
Sr. VP of Marketing & Business Development,
Nabors Drilling USA LPDENNIS A. YANCHAK
Sr. Geosciences Advisor, Apache Corp.
Vice President, Digital MediaRONS DIXON
Senior Vice President, Consulting GroupE. KRISTINE KLAVERS
Executive Vice PresidentFREDERICK L. POTTER
President & Chief Operating OfficerKEVIN F. HIGGINS
Chief Executive OfficerRICHARD A. EICHLER
E P
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A s the worlds largest consumer of oil, gas, and elec-tricity, the US has deemed developing domesticenergy sources to reduce reliance on imports andensure security of supply a major priority. As a conse-
quence, the country is seeking to diversify its energysupplies, creating a range of long-term and large-scaleopportunities at every stage of the supply chain.
These are some of the key trends identified by EICConsults USA Country Overview report published inFebruary 2012, which provides a comprehensive analysisof contemporary developments in the US energy sector.It also looks at where the key hotspots of activity can befound in the upstream sector today.
In the past few years, the US has undergone a seismicshift in the energy market. The latest Consult USA Report highlights several key developments that are
shaping the marketplace.
Recovery of offshore deepwaterdrilling in Gulf of MexicoUpstream developments in the US have been revolution-ized by new technology. Firstly, the report shows that offshore, spar platforms, andsemi-submersible drilling rigs have allowedoil and gas production in federal OuterContinental Shelf (OCS) waters to moveinto far greater depths at more than 1,500m (5,000 ft). Indeed, by 2009 ultra-deepwa-
ter oil production in these depths had over-taken oil production in shallow waters, with84% of proven federal offshore oil and gasreserves residing in more than 300 m (900ft) water depth.
E&P is currently centered on the federalOCS areas of the Gulf of Mexico (GoM)due to ongoing drilling moratoriums in the
Atlantic and Pacific oceans. However,extensive pipeline infrastructure hasrestricted the use of FPSO units, withonly one planned for 2012.
New federal bureaus responsible for energy opera-tions were inaugurated following the Macondo oil spillin 2010, bringing comprehensive new regulations tothe offshore sector. These new permitting regulations,
which came into effect in October 2010, require higherstandards regarding well design, casing, and cementing.
Operators have adjusted well to the new framework. With more than 130 new well permits having been
granted since the new regulations came into force,offshore developments are gaining momentum andsteadily recovering toward the levels seen prior to theMacondo disaster.
The report finds that currently there are 5,981 activeleases in the GoM. Key project developments includeShells Cardamom oil field, the first deepwater plan tobe cleared after the Macondo disaster; Chevrons BigFoot deepwater oil field; BPs Mad Dog oil and gas field;
Anadarkos Lucius oil and gas field, where appraisaldrilling took place in July 2011; and future projects suchas ExxonMobil and Anadarkos Hadrian oil and gas field,
where first production is expected to begin in 2014.
The growth of shale gasSince the development of onshore hydraulic fracturingand horizontal drilling, commercial production of shale
May 2012 | EPmag.com 8
industryPULSE
US upstream promises opportunitiesA new report shows US production and optimism on the rise.
Dr. Phil Goddard , Director of EIC Consult(the Energy Industry Councils research
and consultancy business)
Colorado, Alaska, Texas, and Pennsylvania join the GoM as key US hotspots for
resource development. (Charts courtesy of EIC; Source: EICDataStream)
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oil and gas has grown on an enormous scale.The report highlights that a particular focusis the development of liquids-rich plays that,
due to low gas prices and high oil prices, areset to enjoy years of growth. Daily produc-tion from shale gas increased from 1 Bcf/din 2003 to almost 20 Bcf/d by mid-2011 andcould reach 30 Bcf/d by 2020.
In the past five years alone, the innovativeapplication of technologies for tapping gasfound in shale and other types of rock hasenabled a 20% rise in US natural gas pro-duction and restored US gas output to lev-els not seen since its peak in the 1970s.
As of 2010, there were at least 22 major
shale plays in the US spread over more than20 states. The oil-rich Bakken in North Dakota and theTexas Eagle Ford plays were identified as the center of many operators long-term shale plans. The Bakken inparticular is experiencing rapid development on a pro-lific scale. The US Geological Survey estimates that it holds 3.65 Bbbl of recoverable crude oil in addition toaround 2 Tcf. This development, coupled with NorthDakotas favorable tax system, has delivered a monumen-tal annual increase in the states oil production, with 2010production up more than 40% over 2009 figures.
Intensive drilling is driving up demand for develop-
ment and production services, with operators on thelookout for new technologies to maximize output of
wells with notoriously high decline rates. Despite muchpublic opposition, the comprehensive or prohibitiveregulation of shale gas is unlikely due to the numberof jobs created and taxes generated.
As more shale formations are explored and entercommercial production, estimates of technically andeconomically recoverable shale resources will continueto rise. Elsewhere, conventional upstream developmentsin the US have benefited from this newly developedrecovery technology. EOR has successfully boosted pro-
duction in the Permian basin, and CO 2 injection is now seeing more widespread use in raising production inolder fields across the states.
LNG import terminals shift to export facilitiesThe increase in shale gas development also has led toexisting LNG import terminals being converted to oper-ate as export facilities, according to the report. By July 2011, LNG imports were down 44% compared with thesame time in 2010, and Reuters has estimated imports
were at the lowest monthly level since December 2002. At the same time, however, exports almost doubled from
33.355 Bcf in 2009 to 64.793 Bcf in 2010 as a result of the re-exportation of LNG imports.
However, the future of LNG remains uncertain as themarket for US exports is far from secure. Furthermore,the proposed export terminals are located on the East Coast, lacking a direct route to the most profitable Asianmarkets. It also should be noted that for US natural gasto be competitive in the global LNG market, domesticprices are required to remain moderately low for the 25-
year life cycle of an export project.Lastly, natural gas storage capacity is increasing to
accommodate shale output, with many new storagefacilities entering construction.
Key hotspots of activitySo where are most project developments taking place?The EICs project database, EICDataStream, which istracking more than 9,000 active and future projects acrossthe global energy industry, shows that the key hotspots of activity in the upstream sector can be found in the GoMas well as in the states of Texas, Colorado, Alaska, andPennsylvania. The chart above shows the number andpotential investment value of active and future upstream
projects in these regions, with the GoM leading the way with 71 projects with a combined value of US $54 billion.
The future With oil prices continuing to rise, the US is clearly focused on reducing imports and developing domesticenergy resources. Diversifying energy sources andexpanding production also are seen as key priorities.
With industry innovation driving new techniques toextract resources from more challenging environments,there are plenty of opportunities across the whole sup-ply chain for the long-term future.
May 2012 | EPmag.com 10
industryPULSE
Deepwater and ultra-deepwater projects account for an increasing amount of
production from the US GoM. (Source: EIC Consult - US Project Opportunities)
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When youthinkof petroleumengineeringand petroleum geology/geophysicsprograms, the Universityof Oklahoma's MewbourneCollegeof Earth &Energymightbe the first collegethat comes to mind, and it should be .
Home to the world's first schoolof Petroleum Geology, granting the firstdegree in 1904Home to the world's first school of Petroleum Engineering
Alma mater to more petroleum eng ineers and petroleum geologists thanany programin the world
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Finding the next big thingThe recipe for a successful geoscientist? Travel the world and ask a lot of questions.
A s a geoscientist with Chevron Energy Technology Co., Andrew Kulpecz has found dynamic andexciting work that capitalizes on his science back-ground and love for teaching. A member of the Reser-
voir Prediction team, he is part of a group working with the different operating companies to contributeto the biggest exploration and development projectsbeing undertaken worldwide. And he teaches class-room and field courses to new hires in the US andinternationally.
This mix of fast-paced, ever-changing work suits him.He grew up in the UK, the Netherlands, and Syriacourtesy of his fathers career as a geologist and seniorexecutive for Royal Dutch Shell. Kulpecz returned tothe US for his undergraduate studies at WheatonCollege as a history major before falling in love with
geology. He then earned his masters and Ph.D.degrees in geological sciences at Rutgers University.
On graduating, he found the decision to work in theenergy industry was easy. I really enjoy the teamworkthats used in industry to solve problems, he said.
At Chevron he is a sequence stratigrapher and sedi-mentologist, a natural fit given his sharp interest innature and history nurtured by road trips his family took to the Alps, the Dead Sea, Jordans Petra, andother far-flung natural and man-made wonders. I loveunderstanding the way things work today and thenapplying those concepts back through geologic time
in the search for hydrocarbons, he said.This past year he spent six months as an ex-pat in
Perth, Australia, working on reservoir characterizationand front-end geology for the Gorgon and Wheatstonenatural gas projects, on which Chevron will spend US$40 billion to develop. Hes also studied emergingbasins in Brazil, the Arctic, Angola, and offshoreCanada, among others. He is married with two youngchildren, whom he intends to someday submit to thesame educational family travels he benefited from.
In an interview for Hart Energy, Kulpecz shared hispassion for his work.
What role does your group play within Chevron? We evaluate basins for our exploration and new venturesbusiness partners. We interpret 3-D seismic, study welland core data, and run paleoclimate and forward strati-graphic models and more to understand and predict thepresence of both reservoir and source rock. These inter-pretations assist in risking different projects and decid-
ing whether to enter new basins, bid on lease blocks,and drill exploration wells.
A lot of these basins have sparse data, so its a chal-lenge. Theres much uncertainty, so its difficult to makerobust predictions about what youll find. But thats
what makes it fun you get to be innovative and usetechnology to develop accurate forecasts.
What project that you have worked on is furthest along? The Gorgon and Wheatstone liquefied natural gas proj-ects, where Chevron has had a good run of success indrilling and finding natural gas resources. A lot of the
Andrew Kulpecz, geoscientist with Chevron Energy Technology
Company (Image courtesy of Chevron Energy Technology Co.)
Susan Klann ,Managing Editor, Oil and Gas Investor
May 2012 | EPmag.com 12
worldVIEW
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other projects are new ventures looking for the next big thing.
What does your teaching entail? Given the current demographics of the industry, thereare a lot of young employees. I teach new hires both inthe classroom and in the field. This past year I taught stratigraphy courses in Australia and Indonesia andled field trips to Utah and New Mexico to teach key concepts. Students can look at outcrops that are onthe same scale as the reser voirs theyll be working on.
I also teach integrated teams of modelers, scientists,and engineers. The goal is to get the whole team out together to look at analogs for reservoirs so they can
be on the same page.
What is your take on the concept of peak oil? With any finite resource theres going to be a peakand eventual drawdown. But the industry is constantly pushing technology boundaries to further the recov-ery of existing resources and to find new ones. In just a decade, weve revolutionized the way we look for gas.The industry is very good at what it does.
Will you be working in shale plays internationally? Chevron has acquired acreage in Poland, Romania,
and Bulgaria. The company is positioning itself rela-tively close to major markets in Europe and Asia. Imcur rently dealing with more conventional clastic andcarbonate reservoirs, but as the portfolio evolves inthe coming years, I will probably be working onunconventional plays.
Given your studies of paleoclimates, what are your thoughts on climate change? I recognize the concerns about climate change, and
we must be mindful of the environment. Recent stud-ies have focused on looking for periods when CO 2 was
as high or higher than it is today to understand what could occur in future scenarios. In our work at Chevron, we use paleoclimate models to understandenvironmental conditions in geologic time to predict
where reservoirs will be today.
You mentioned the many new people entering the industry.What has helped you be successful so far in your career? Its important to find something you enjoy and can bepassionate about. Seek senior mentors and assign-ments that are challenging, where you can grow andlearn. And dont be afraid to ask questions.
May 2012 | EPmag.com 14
worldVIEW
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The R5 qua l i ty, deve loped by Vicinay Cadenas is the resultof our c o m m i t m e n t w i t h the off sho re i ndus t ry to develop to pqua l i ty p roduc t s with i nnova t ive so lu t ions .
This quali ty has a 16% h igher r e s i s t ance t han cha ins in R4 andits w ei ght is more than 16% less. The new R5 qua l i ty offe r s ar ange of possibi l i t ies for t he des ign of mooring lines d e p e n d a n ton the specif ics of each project .
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interrupting drilling. Such an upgrade project wouldnormally involve towing the rig to a dockyard in Asiafor a layup of several weeks.
Careful planning coupled with our technical andproject management expertise enabled us to propose anoptimized solution, said Venkata Srinivasan, E&A engi-neering manager of Wrtsil Services in Australia. Takingonly one engine offline at a time and working within theavailable window periods, the work was successfully com-pleted in approximately three months without interrupt-ing drilling.
Overcoming challengesThe rigs four 28-year-old 1.8 MW diesel engines requiredcomplete overhauls, and the four sets of engine controls,generator controls, and governors needed to be replaced.
Limited space on the rig was a considerable challenge interms of finding storage space for the almost four tonnesof machinery and equipment needed for the upgrade andaccommodating the servicing team members. Wrtsilhad to carefully map out the project stages to ensure that the necessary equipment and the team members with theright skills were all onboard the rig at the right time.
On the basis of a detailed technical audit of the rigsobsolete power management systems, which had limiteddocumentation, our team carefully studied the issues they had with the present system and came up with a detailedreport and recommendations for the customer on thecomponents that needed to be replaced or upgraded,
Wrtsil Australia Technical Manager Matt Riley said.The Nan Hai VIs revamped power system incorporates a
SCADA system featuring two Wrtsil Operator InterfaceStations (WOIS), whose LCD screens enable the constant monitoring and touch-screen operational control of therigs power source.
Completing this kind of upgrade while enabling a rig tocontinue uninterrupted drilling in its offshore locationcan result in substantial savings for customers. Accordingto David Roberts, sales manager at Wrtsil Australia, well
planned and executed onsite upgrade projects can avoiddowntime that would effectively cost millions of dollars.
Maersk Drilling also was satisfied the upgrade could besuccessfully planned and executed while the rig remainedfully operational. The rigs new reliable electricity supply
will be the basis for the safe and successful operation of Nan Hai VI in the future, Neumann said.
Modular solutions create seamless connectionsbetween different systems. This reduces risks, costs, andexecution times, also allowing repeatability and scalability for future operations and maintenance.
Dynamic maintenance planning According to Klockars, constant monitoring enablescomprehensive dynamic maintenance planning basedon actual conditions. The online systems, for example,transmit real-time data to Wrtsils Condition BasedMaintenance Center in Vaasa, Finland. These data areanalyzed monthly to create summary reports andupdated recommendations. We also give six-month pre-dictions for future maintenance needs, Klockars said.Selected components are additionally inspected visually on a periodical basis in tandem with the training of the
rig crew. Data from the online condition monitoring of rig thrusters are sent to the companys Propulsion Con-dition Monitoring System Center in Holland. The result-ant data from all these sources allow Wrtsil to closely monitor the actual condition of vital equipment.
Such technical management agreements are typically made for a minimum of five years, plus an optional five-
year extension, Klockars said. The benefits to customersinclude reduced fuel and maintenance costs, the pro-longed lifetimes of components, savings on the time spent by rig crew on monitoring and maintenance, and fewerunplanned stoppages due to component failures andunscheduled maintenance work.
Successful onsite upgrade at seaIn 2010, Wrtsil Services Australia carried out a majorpower management system upgrade on the Nan Hai VI semisubmersible exploration and appraisal drilling rig inthe Carnarvon basin offshore Western Australia. The rig,owned by Chinese Oilfield Services Ltd. (COSL) and man-aged by Maersk Drilling Australia, had started to sufferfrom power problems in 2009 while prospecting for oilbeneath the Indian Ocean. We realized we needed to
replace the engine control system because of its obsoleteparts and the lack of knowledge to enable field engineersto service existing equipment, Ulrich Neumann, techni-cal superintendent, Maersk Drilling Australia, said.
Maersk Drilling and COSL challenged Wrtsil toidentify the root causes of the power managementproblems and find ways to resolve these issues without
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Meeting production targets is a continuous chal-
lenge, and many components of a field operationhave the capacity to significantly impact the economicsuccess of an asset. Fast and easy access to reliable infor-mation whether real-time or historical is critical toenable engineers and management to make the right decisions at the right time to meet both operational andlonger-term strategic objectives. This is the case whetheronshore or offshore and in conventional or unconven-tional fields.
In most cases, production operations are becomingmore complex, and with field automation, the volume of measurement data is growing exponentially. In addition,
engineers are being tasked with managing an increasing
number of wells. To work efficiently, engineers need to bepresented, at the right place and time, with informationtuned to their particular needs, whether for routine sur-
veillance, extensive diagnostic analysis, or as the basis for
intervention and treatment programs. A wide range of automated systems has been developed
in past years to support production management, such asdownhole and surface measurement devices, data histori-ans, and business performance and reporting processes.However, many of these systems are difficult to maintainand become obsolete. In addition, despite considerableand often costly efforts to integrate disparate softwarecomponents, they often fail to communicate effectively across the whole operation.
To meet this challenge, Schlumberger released the Avo-cet integrated production operations software platform,
which enables production managers and asset teams tosee a clear and complete picture, understand productionstatus and field events, identify the root causes of produc-tion shortfalls, and act effectively to close the gap betweenpotential and actual performance.
The platform combines the functionality of a range of proven information management and operations man-agement tools into one complete software solution. It combines well operations and production data manage-ment systems to deliver a clear, complete, and up-to-datepicture of operations, from capturing and validatingfield data to production and equipment surveillance
and tracking of specialized oilfield operations. The plat-form integrates with corporate datastores, accountingand fiscal modeling systems, and other applications. Sig-nificantly, the platform connects directly to petroleumengineering simulators and analytical applications toprovide insight into the root causes of production short-falls. By uniting data with models in a single environ-ment, problems can be identified more quickly,downtime minimized, and production optimized.
Built-in flexibilityEvery producing asset brings unique production chal-
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Integrated operations platformovercomes production challengesBy improving data quality, automating routine operations, integrating workflows, and unitingdata and models in a common environment, a new platform gives operators a clear pictureof field production.
Colin Smith , Schlumberger
The flexibility of the Avocet platform enables solutions for inte-
grated operations, including monitoring and optimizing artificial
lift systems to maintain optimal lift performance and maximize
pump run-life. (Images courtesy of Schlumberger)
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With a third major expansion since 2007 , NOV" isc o n s t a n t ly e x p a n d i n g our m a n u f a c t u r i n g , s e rv i c e a n dsupport structure to better serve our cus tomersaround the globe. As your business grows - growwith a p a r t n e r t h a t is b e t t e r prepared for t h e long run.
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lenges, which can demand new or nonstandard solutionsto address them. This software platform can capture allavailable measurements and workflows, which can beincorporated and tailored to meet the specific needs of dynamic field operations (e.g. new measurements orequipment types) and different types of users, such asengineers and asset managers.
Avocet has been developed using global industrystandards to support audits, security, and regulatory compliance. The platform has been built on a modernMicrosoft foundation and is open and extensible. Cus-tomized software extensions and tailored calculationscan quickly be added to meet exact requirements.
A Microsoft Silverlight interface allows fullaccess to the platform on the web for fast dataentry and validation, a common view for shar-ing information between the field and officelocations, and faster identification and man-agement of operational issues.
Integrated technologyfor the integrated assetThe integrated platform can collect all types of production operations information from sub-surface, wellbore, wellhead, surface networks,and facilities. Example applications includecomprehensive solutions to monitor and ana-lyze multiphase meter measurements and mon-itoring and optimizing the performance of artificial lift operations. Other applicationsinclude detailed visualization of wellbore con-
figurations and the tracking of wellbore workovers;authorizations for expenditure, including perforating andstimulation operations; and integrity parameters for
mechanical surveillance.Model-based flow assurance surveillance functionality
helps users understand and predict problems such as scaleprecipitation and CO 2-induced corrosion. Tight integra-tion with the PIPESIM steady-state multiphase flow simula-tor allows for design and diagnostic analysis of oil and gasproduction systems. These software tools model multi-phase flow from the reservoir to the wellhead and analyzeflowline and surface facility performance.
Sharing architectural components enables OFM welland reservoir surveillance software projects to be set up
with just a few mouse clicks within the platform. This capa-
bility provides advanced production surveillance views andpowerful production forecasting tools to manage andimprove oil and gas field performance throughout theentire life cycle. It allows all asset disciplines to view, relate,and analyze reservoir and production data with compre-hensive workflow tools such as interactive base maps withproduction trends, bubble plots, diagnostic plots, declinecurve analysis, and type curve analysis.
Tight integration with the OFM well and reservoir analy-sis software also delivers easy flow of data collected and veri-fied by the Avocet platform into the Petrel E&P softwareplatform for tasks like production history-matching and
model validation from the ECLIPSE reservoir simulator.
Production computations & industry standardsThe integrated platform can perform full-stream and com-ponent-based allocation for a wide range of fluid and dis-position types. API, ISO, and AGA standards are used for
Avocet provides detailed visualization of wellbore configura-
tions, and its data storage is date-effective so that changes
can be tracked through time.
Projects and data transfers in GIS-enabled OFM well and reservoir analysis
software can be set up in just a few mouse clicks using the Avocet platform.
digitalOIL FIELD
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volume computation and temperature and pressure cor-rection. Theoretical methods can be used for wellhead esti-mation and setting up allocation using network schematics.
Operations data are automatically loaded from SCADA systems, data historians, and other business systems usingOLEDB, ODBC, CSV, and XML formats. The platformalso supports the Energistics PRODMLand WITSML standards for data trans-fers. NORSOK D-010 and other wellintegrity standards are supported for
well design, planning, and the execu-tion of safe well operations. All datacaptured and stored in the platform isdate-effective and version-controlled tosupport the demands of audits and Sar-
banes-Oxley requirements.
Information to actand add barrels
The integrated production operationssoftware platform benefits a broadrange of producing asset disciplines field staff, production and reservoirengineers, production accountants, andadministrators. Asset managers are ableto view asset performance, monitor key performance indicators, and visualize
relevant information that can affect production and impact performance.Production managers can visualize asset performance, including allocated pro-duction against plan for a full portfolioof assets in a consistent manner, in a sin-gle environment, regardless of asset type or where the assets are located.The platform includes the capability touse the classifications of downtime toprovide the basis for the analysis of pro-duction shortfalls root causes can be
assigned, identified, and tracked forcontinuous performance improvement.
The platform provides easy access torobust tools and techniques foradvanced data mining, artificial intelli-gence, and petroleum engineeringanalysis to detect anomalous behavior,estimate well performance, or providedata-driven candidate selection. Reportscan be generated to meet operational,management, partner, and regulatory requirements.
By improving data quality, automating routine opera-tions, integrating workflows, and uniting data and modelsin a common environment, the Avocet platform provides
operators with many new opportunities to improve fieldperformance and ultimately add barrels to consistently meet production targets.
digitalOIL FIELD
You use increasing ly sop histicated technology in extremel y challengingenvironments . You need to ensure the highes t levels of efficiency,reliability and safe ty . Soft can hel p. Onl y Soft has Li-ion batteriescapable of performing at up to 125 'C and presenting no danger up to150'C . Whether you need a custom -designed solution , or whether ourcomprehensive range of primary batteries will do , you can count onSo ft ' s unparalleled experience to power your MWD , LWD, PIG andother high-temperature oil and gas tools .
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B G P -A reliable partner f o r youBGP is a leading geophysical contractor , providing geophysical services to its clients worldwide. BGP now has 50branches and offices , 65 seismic crews , 6 vessels and 14 data processing and interpretation centers overseas. Thekey business activities of BGP include:
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The Chirag Oil Project is the next major step inthe ongoing development of the Azeri-Chirag-Guneshli field, the largest oil field in the Azerbaijansector of the Caspian Sea. The multi-billion-dollar proj-ect, which was sanctioned in March 2010, is planned toincrease oil production and recovery through a newoffshore facility designed to expand field infrastructurebetween the existing Deepwater Gunashli (DWG) andChirag-1 platforms.
Toward this end, the Azerbaijan International Operat-ing Co. (AIOC), a consortium led by BP, has contractedEmerson Process Management to automate the new off-shore platform. The company is expected to provide theautomation and safety systems, asset management tools,
and a broad range of measurement instruments to helpoperate the platform safely and efficiently. Emerson also
will act as the Main Automation Contractor for the proj-ect, responsible for delivering project management serv-ices to ensure all equipment is properly installed and
integrated to meet technical, budget, and schedulerequirements.
Support for the Chirag Oil Project is being providedby the companys recently expanded base in Baku.Emerson has been represented in Azerbaijan since 1997,
but the new office increases the range of project man-agement and support services to the region and will play a critical role in this oil recovery project.
Project workscopeThe company worked closely with BP for 18 months aspart of the integrated FEED team to define a digitalautomation solution to meet the project needs. Emer-sons PlantWeb digital plant architecture includingFoundation fieldbus communications, digital automa-tion systems, asset management software, and intelligent field devices will provide process control and access to
management information. Its network of intelligent transmitters and valve positioners also will deliver con-tinuous process and equipment health information toidentify potential problems before they affect opera-tions. These predictive capabilities also will help to
deliver high platform uptime. As part of the PlantWeb architecture,
the DeltaV digital automation system forprocess control and DeltaV SIS processsafety system for process shutdown andfire-and-gas monitoring will enable securecontrol of oil production on the platform.
Additionally, AMS Suite predictive mainte-nance software will provide online access toinstrument and valve diagnostics and auto-matic documentation of field device main-tenance information all contributing toongoing efficiency of platform operationsand maintenance activities.
digitalOIL FIELD
Digital automation solution enhancesoil recovery in Caspian SeaAutomation services and technologies will help recover additional oil from the massiveAzeri-Chirag-Guneshli field in the Caspian Sea.
Raoul Mercer , Emerson Process Management
The AMS Suite APM software is being used as part
of Emersons digital automation solution for the
Chirag Oil Project offshore Azerbaijan. (Image
courtesy of Emerson Process Management)
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digitalOIL FIELD
The AMS Suite: Asset Performance Management, based on Meridiums APM software, features a unified interface to assess asset health and critical-ity, optimize maintenance expenditure, and view key performance indicatorsof asset performance that help guide maintenance decision-making. Asset
Performance Management also allows performance comparisons of key assets at other locations.
Emerson is delivering a range of solutions to monitor and preserve the effi-ciency of operation. For example, Roxar corrosion monitoring equipment canbe used to monitor the internal condition of pipes, verify their integrity, opti-mize corrosion mitigation, and support inspection planning and plannedasset maintenance. And a nonintrusive acoustic sand monitoring system alsocan provide efficient monitoring of sand production at the field. AdditionalRoxar intrusive systems will give direct information about the erosion effect of produced sand. Corrosion and sand erosion data will be integrated within anonline system, enabling data management and reporting.
A range of measurement instrumentation including Rosemount level,
pressure, and temperature transmitters will be installed throughout the plat-form. Advanced integrated diagnostics will help to identify potential prob-lems before they cause a disruption to production. For example, EmersonsRosemount guided wave radar transmitters will be deployed to monitorlevels within inlet separators and scrubbers. These devices incorporateadvanced diagnostics that help to identify any build-up on probes thatcan potentially cause problems. Early warning enables maintenance tobe scheduled to minimize disruption.
The companys Micro Motion mass flowmeters are to be deployed forcritical chemical injection measurement applications at the field. Under-injection of inhibitor chemicals can lead to mechanical problems, whileover-injection can increase costs and adversely affects downstream fluid
characteristics. Coriolis mass flow measurements, meanwhile, will providethe highest levels of accuracy and reliability.
TopWorx Valvetop Discrete Valve Controllers will deliver control and posi-tion indication feedback for pneumatically actuated ball isolation valves,and Foundation fieldbus communications will enable seamless interfacebetween the automated isolating valves and the integrated control systems.
Commissioning and support With Emerson responsible for all automation engineering and acceptance
testing and for supporting BP with commissioning, configuration, and start-up services, the Chirag Oil Project is set to deliver additional hydrocarbonsto secure energy in a key region of the world. BP has estimated potential
ultimate recovery from the supergiant field at more than 5 Bbbl of oil.The commissioning will initially take place onshore Baku, including all
loop checkouts and loop tests before the final offshore hook-up, and the AMS Suite will be used to streamline device configuration, commissioning,and system validation, helping to ensure the project meets its tight deadline.
Construction of the AIOC-operated project is scheduled for completion in2013 to be followed by first oil. After startup, the local Emerson team willprovide ongoing support services to the BP consortium, with the companysengineers based permanently on the platform for an initial period to pro-
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When we introduced the GeoSt reamer solut ion , anew standard wa s set within marine seismic.Enhanced with the GeoSource technology, we nowoffer the first t rue ghost-free solution.
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I n the latest iteration of lets look like were doingsomething, the US Department of the Interior(DOI) and the Bureau of Ocean Energy Management have announced that the DOI is taking steps to assessthe conventional and renewable resource potential inthe Mid- and South Atlantic. A draft ProgrammaticEnvironmental Impact Statement (PEIS) was released
March 28 for public comment and is intended to deter-mine whether, and if so where, leasing would beappropriate in these areas.
More to the point, the draft PEIS will assess, andpotentially green-light, geological and geophysicalactivities.
While the DOIs announcement referred to this deci-
sion as a milestone, those in the industry were lessecstatic. Why? On its face, this looks like progress. Nooil and gas activity, including G&G activity, has takenplace in the US portion of the Atlantic Ocean indecades. Its possible that areas off the East Coast might be analogous to some of the geology offshore North
Africa, where major discoveries have occurred.But while the DOI announcement goes into great
detail about the need for G&G studies, it neglects tonote that there are no lease sales planned anywhere off the East Coast in the 2012-2017 OCS leasing plan. And
while several permits have been filed to carry out G&G work in the area, most of these were filed when thedrilling moratorium off the Atlantic coast was tem-porarily lifted in 2008.
With the removal of any lease sales from the pro-posed 2012-2017 Five Year Leasing Plan currently under consideration, the economic or financial incen-tive to acquire that data and offer it for license hasbeen removed, said Chip Gill, president of the Inter-national Association of Geophysical Contractors, in his
organizations official response.Gill also expressed disappointment that the North
Atlantic Planning Area was not included in the draft PEIS. The wind doesnt stop at the New Jersey stateboundary, and neither does oil and gas prospectivity,he said, adding that Shell Canada is spending US $1 bil-lion to explore for oil and gas offshore Nova Scotia, just north of the North Atlantic Planning Area.
Currently, DOI Director Ken Salazar is reviewing thecomments and is expected to allow surveying to start next year. Oddly, the environmental groups are no hap-pier about the decision than the oil and gas industry,
though for different reasons.Todays announcement is great for petroleum
companies but horrible news for our coastlines and apotentially deadly blow to ocean fisheries and wildlife,Natural Resources Defense Council President FrancesBeinecke said in a statement.
It would seem, based on theimmediate backlash to theannouncement, that the deci-sion is not really great foreither side.
Does the US government
need a lesson in economics?Will geophysical contractors shoot seismic in the Atlantic Ocean just forthe heck of it? Probably not.
Read more commentary atEPmag.com
RHONDA DUEYExecutive Editor
29
explorationTECHNOLOGY
EPmag.com | May 2012
Seismic contractors are not likely
to rush into Atlantic exploration
just because they can. (Image
courtesy of PGS)
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D ownhole tools are valued for their ability to lowercosts and decrease the time it takes to get to first production.
From the bit to the top drive and the fluids circulat-ing through the annulus, each component shares thestake in both outperforming past results and overallfailure. Todays drilling technology market is strong,and it boasts a wide variety of processes and tool
suites that give operators more confidence. Work isdone safely, with more efficiency, and everyone bene-fits when a job comes in under budget.
But the question remains, Who takes credit forimprovements in efficiency?
As youths, my father and his younger brother used topick cotton for extra money. He once told me that hisbrother had a knack for the activity. At the end of theday, no matter how hard he tried to out-pick him, my uncle always came to the scales with more cotton totrade. I never could figure out how he did it, but healways beat me, he said.
Its true that at the end of the day, some peoplealways end up with more cotton in the sack than theircompetitors. This analogy is simplistic when comparedto tools supplied for well construction, but it stillmakes sense.
With each new benchmark,performance results are veri-fied and published. Each stake-holder supplies its various
clients with the story of savingdays and trips in an otherwise
difficult drilling scenario. Opera-
tors cite mobilization strategies;drilling contractors cite experi-
enced crews and engineeringdesign; and tool companies makeclaims based on advanced,
propriety technology. Thesavings are apparent,
and performance gainsprovide confidence
within all facets of thedrilling market.
Case studies for a particular tool or process can iden-tify the specific drilling problem or challenge, the solu-tion applied, and the end results. Highly engineeredsolutions deserve recognition when it is due, and themost advantageous means of drilling in troublesomeenvironments soon becomes the new standard practice.In the meantime, engineers and technology providerscontinue to scramble to innovate further. Benchmarkscontinue to become more impressive. Lessons learnedbecome the foundation of new research.
The real answer is that everyone participates in
the success of improved well construction methodolo-gies. This is evidenced by the wide range of paperspublished by a variety of trade organizations andother institutions.
The nature of competition contends that companiesmust garner improvements in well construction to
validate their internal research and subsequent lab work. Putting a new tool in the field is no small feat as virtually no operating company wants to be the firstone to deploy an untested technology. Once this trialperiod is accomplished, the results are then quantifiedinto how much it saved either by cost of investment or
in time/day rates. This information is then pushedout to encourage repeat business and to bring onnew clients.
Thinking back on my fathers analogy, Ive often wondered if he would have had a different experiencehad he taken a different tack. Rather than focusing onpicking more cotton than hisbrother, what would have resultedhad they formed a joint effort?Most likely they would haveshared an overall gain.
wellCONSTRUCTION
Performance is a shared benefit
Shaving days from the drilling and completions time cycle is a worthygoal, but who gets to take the credit?
Read more commentary atEPmag.com
TAYVIS DUNNAHOESenior Editor
EPmag.com | May 2012 31
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The implementation of intelligent energy or smartdigital oil field technologies has been a hot topicfor the upstream industry. Its come a long way in arelatively short time (about 10 years), with a lot of talkand behind-the-scenes development early on and not much proof. As a result, it is still viewed by some as anitem to be filed in the IT folder, with its impact onday-to-day operations negligible.
As the approach is more firmly embedded in com-
panies around the world, the results in terms of risingproduction levels are starting to speak for themselves.
In the early days of implementation it was hard toquantify the benefits, but BP is one company that, viaits Field of the Future program, is reaping therewards. While chatting with BPsSteve Roberts, vice president of the flagship technology pro-gram, at the SPE Intelligent Energy International event inUtrecht, the Netherlands,Roberts made it clear the com-
pany is seeing quantifiableproduction optimization bene-fits from implementing intelli-gent energy solutions.
At the end of 2011, the opera-tor estimated it had incremen-tally increased production levels by 73,000 net boe/d directly as a result of the pro-gram. It has an internal goal of 100,000 boe/d by 2017 and Roberts said the company is well ahead of that schedule.
Key features of the program include reducing oper-
ational risk, automating routine tasks, optimizing pro-duction, and continuously improving. Technologiesbeing implemented include real-time tools for moni-toring facilities and predicting failure to enable proac-tive maintenance, particularly in key areas such asrotating equipment and where corrosive materialsare being used.
Roberts said effective solutions have been deployedinto eight of BPs operating regions, including Alaska,
Angola, Azerbaijan, the Gulf of Mexico, the North Sea(UK and Norway), Oman, and Trinidad. It also has
observed similar progress being made in other compa-nies, he added.
Roberts also pointed out that BPs digital oil fielddrive has focused mainly on alignment around a corefocus area, driven by its portfolio, where a significant
proportion of total production is depend-ent on a comparatively small number
of wells. These wells are typically (but not exclusively) high-rate oiland gas wells in moderate to deep- water depths, on fields producingunder waterflood and with a
propensity for sand production.It has therefore made perfect
strategic sense for the company toprioritize and target this element
of the portfolio, and it is pushingon rapidly with its next generation
of solutions. According to Roberts, BPhas begun to change its strategy andapproach to enable this and is aspiring
to become fully empowered by real-time information tomake better decisions faster, he said.
Edwin Verdonk, vice president of Subsurface Expert-
ise and Technology Deployment at Royal Dutch Shell, was in agreement. We see that the speed and imple-mentation of new technology is faster than ever before,and thats very important, he said. When you look at the changing world and the complexity of the chal-lenges facing us, technology is going to get us to a dif-ferent place, a new level.
When talk is turned into results asquickly as the digital oil field initia-tive has done, you can see what he means.
productionOPTIMIZATION
Turning fast talk into fast resultsThe digital oil field concept has come a long way in a short time, withresults in terms of increased production now backing up all the early talk.
Read more commentary atEPmag.com
MARK THOMASInternational Editor
When you look at thechanging world andthe complexity of the
challenges facing us,technology is going to
get us to a differentplace, a new level.
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giants projected share of capex to 2016 is forecast tomake up more than a quarter (26%) of the total globaldeepwater spend and will be directed predominately toward its presalt assets in the Santos basin.
Adding to this will be high investment levels by thesupermajors, the firm said. Chevron, Total, Shell, BP, andExxonMobil will, combined with Petrobras, make up morethan two-thirds (65%) of the total global deepwater capex
figure to 2016.The growing influence of independent operators such
as Anadarko Petroleum, Noble Energy, Hess, and Tullow Oil also is apparent, with these companies expected tosubstantially increase their proportion of capex within thedeepwater market over the next five years. For Anadarko,the rise in investment is particularly significant, with key projects including the GoMs Lucius project and excitingnew developments offshore East and West Africa.
In terms of reserves coming onstream over the period2012-2016, from a regional perspective it is again Latin
America (almost entirely Brazil) that will dominate, with
the area forecast to supply 39% of total global reservesadditions. More than 60% of these are projected to comefrom Brazils presalt basins.
However, the largest deepwater field development expected onstream during the same five-year period islocated offshore Australia at a depth of 1,300 m (4,265 ft),
with the ExxonMobil-Chevron joint development at Jansz(Greater Gorgon) expected to start flowing in 2014 withreserves totaling some 2.8 Bbbl.
Offshore Africa, Infield anticipates strong investment willcontinue, with the region holding an equal global deepwa-ter capex share to that of Latin America at 30% across the
2012-2016 timeframe. Comparatively, North Amer-icas capex share of the market is expected to standat 21%, followed by Europe and Asia.
The largest technology segment for investment willbe pipeline installations Infield expects this to com-prise 39% of total global deepwater expenditure.Latin America and Africa are expected to account for the greatest proportion of deepwater pipelinespend, although the single most capital-intensivepipeline project is expected to be Gazproms SouthStream development, which was approved recently by the Russian government and which will be situ-ated in up to 2,200 m (7,218 ft) water depth.
Subsea spend stays strong
Deepwater subsea expenditure is expected toremain high, with projects offshore West Africaforecast to comprise the largest share of subseademand over the same five-year period.
According to Infield, oil and gas operators venturinginto deeper, harsher, and more remote locations increas-ingly need top tier equipment often at a significantly higher cost than more standard equipment to accessthese reserves.
Ultra-deep installations will account for almost 25% of the annual subsea tree market by 2016, and Infield saidthe potential for subsea capex throughout the forecast
period has increased dramatically.Petrobras is again a leading light, with an expected
capex of US $18.9 billion between 2012-2016 and key developments such as the pilot projects on the Iara andGuara fields and a series of extended well tests on Iara,Libra, Franco, and Iguacu fields. In Brazil, an estimated38% of the projected subsea capex will be needed todevelop the regions presalt projects.
Prospects for manufacturers also are looking positiveglobally, with the market outlook showing a well-suppliedmarket with a total capacity of 690 trees. Toward the endof the forecast period, Infield expects higher utilization
rates and the start of a saturated market, driven mostly by the increasing demand for subsea trees in main phases inBrazil and West Africa.
Global subsea tree manufacturers utilization rates areexpected to increase to an average of 75% in the next three years, up from 49% in the 2009-2011 period.
Advanced seabed technologies Advances in technology are increasingly being tested anddeployed in response to the industrys insatiable demandfor solutions to deepwater and harsh environment chal-lenges as well as sustaining production rates in mature
COVER STORY: DEEPWATERCHALLENGES & SOLUTIONS
By 2020, deepwater production from the current major contributors will
have risen still further but with growing contributions from emerging areassuch as Australia, Israel, Malaysia, and Indonesia. (Source: Rystad Energy;
McKinsey analysis)
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COVER STORY: DEEPWATERCHALLENGES & SOLUTIONS
developments, boosting flow rates in low pressure reser- voirs, accommodating a larger number of fields tiedback to host facilities, and ensuring the energy and cost-efficiency of a project.
Infield highlighted that potential projects that couldbenefit from the use of advanced seabed technologiesinclude mature fields in the North Sea and the US GoM,
where a large number of smaller developments areexpected to be tied back to existing platforms to becommercially viable.
It also expects West Africa will be one of the key regions
for implementing subsea processing because of theregions already extensive deepwater production; signifi-cant oil reserves; and geographical distribution of itsfields, which require multiple wells being tied back tosingle central processing facilities.
In Africa, oil companies such as Total, BP, ExxonMobil,Chevron, and Eni will try to take advantage of the areasample resources to leverage against the declining reservesfrom other mature areas. Total is leading the subseacharge there with a projected $8 billion of expenditure
within the forecast period, according to Infield. Australia also was flagged as a major player in the global
gas market, largely due to the development of its offshorenatural gas projects. Post-2013, a significant backlog of major projects is predicted to provide a boost to the mar-ket, with more than 50% of the forecasted subsea market expected to relate to tiebacks to a fixed, floating, or termi-nal facility.
Lastly, in the GoM the changing regulatory environ-ment governing operators activities will lead to futuresubsea equipment and infrastructure needing to comply
with stricter regulations. This will result in higher safety specifications and consequently lead to greater capitalexpenditure per development, Infield said.
Chevron at the sharp endChevron has been a key player offshore, having invested indeep water for an extended period of time as a major part of its future production profile.
Project expenditure over the next six years will see deep- water projects account for nearly 30% of its total spend,only just behind the companys largest project investment area (LNG), which comprises more than 35% of its totalspend. This year deepwater project startups for Chevroninclude the Usan and Agbami II developments offshoreNigeria and Tahiti II in the deepwater GoM. These will be
followed in 2013 by Papa Terra offshore Brazil and thefollowing year by the Jack/St. Malo, Big Foot, and TubularBells projects in the GoM and Gorgon offshore Australia.
Gary Luquette, president, Chevron North America E&PCo., said, Weve had a strong presence in deep water formany years and are focused on maintaining this going for-
ward. Our exploration success has translated into world-class producing fields such as Tahiti in the Gulf of Mexico,
Agbami in Nigeria, and BBLT in Angola. These projects,along with many others, are delivering about 375,000 b/d.Our success has led to a strong queue of major capitalprojects, resulting in a full pipeline that is expected to
grow our deepwater production to 470,000 b/d by 2017.Chevron has three deepwater projects in various stages
of early startup. In Nigeria it has Usan, with a peak capac-ity of 180,000 b/d of oil, which began production in Feb-ruary. Ten wells already have been drilled, and peakproduction is expected in 2013. Also in Nigeria, the com-pany expects to start production from Phase 2 of Agbami.This was originally planned for 2011, but strong produc-tion performance from existing wells kept the fieldsFPSO at capacity throughout the year. Chevron said it presently is drilling Phase 2 wells to maintain that produc-tion plateau.
Sunrise over Peregrino Brazils presalt development
bonanza is driving the global deepwater market, both in
terms of investment and technology development. (Photo
courtesy of Statoil ASA)
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In the GoM, the companys Tahiti II project is progress-ing despite some delays due to the recent moratorium.The topsides water injection equipment has been installed,
Luquette confirmed, and the operator began injection inFebruary. Were currently drilling and completing addi-tional producers, which are expected to reduce fielddeclines and improve ultimate recovery, he said.
Jack/St. Malo:a template forothersLooking further out to