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WATER MANAGEMENT

Searching for the right mix of ‘shale’and water

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IndustryPULSE:Legal implications of anindependent ScotlandThe country’s independence could

result in a host of issues facing the offshore oiland gas industry.

EXPLORATION & PRODUCTIONW O R L D W I D E C O V E R A G E

MAY 20 13VOLUME 86 ISSUE 5

A HART ENERGY PUBLICATION www.EPmag.com

36

8

WorldVIEW:Growing grounds foroptimism in UK waters

With the UK offshore sector set for a period ofrecord investment, one of the country’s leadingoil industry figures says optimism remains strong forthe industry going forward, both in its home watersand abroad.

12

Unconventional:The Niobrara bringsbig numbers to ColoradoOperators in the Colorado Niobrara

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AKKEN • THREE F O RK S • NI O BRARA • H EATH • MAN C O S • PR O N G H O RN • CC DELL • M WR

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Current Industry Topics• O pening Keynote: Noble Energy 's Niobrara Play• Hess ' Burgeoning Bakken• Building on our successes in the Rockies• Roundtable: Investing in Oil Plays• Ramping Up in the Wattenberg Field

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• Adding More Three Forks to the Bakken Equation• The Bakken Without Borders: The U.S. and

Canada Sides• The Bakken in the Rough Rider Area• Niobrara Economics• Geology S potli g ht• Smarter Field Operations• Technology Roundtable: Innovations in Comp letions• Whiting 's Bakken & Three Forks , p lus the Pronghorn

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ChuckDavidsonChairman and CEO,

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Midstream Track Topics - New for 2013• The Bakken Infrastructure Challenge• Lig ht , Swee t Crude• Refining in the Bakken Reg ion• Panel: Bakken Pi pelines• Panel: The Bakken Via Rail• Moving Crude to Market• The Ed d ystone Project: Railing Bakke n to Pennsy lvania• The Rockies Buildout• Gas Storage in the Niobrara Region

JamesJ. VolkerPresident Woddvede E&P, Chairman, Chairman and CEO,

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AS I SEE ITGolf, anyone? 7

MANAGEMENT REPORTKnowledge layer is next ‘big innovation’ 17

DIGITAL OIL FIELDUnconventionals require nontraditional workflows 20Bringing transportation management to the oil and gas industry 24

EXPLORATION TECHNOLOGYPlanets align for local symposium 29

DRILLING AND COMPLETIONOperators see decades-long promise of unconventional plays 31

PRODUCTION OPTIMIZATIONCarnival comes to the presalt 33

OFFSHORE ADVANCESTwilight years for a tired fleet 35

INDUSTRY IMPACTActive-set cement system can automatically seal leak paths 130

TECH WATCHMaking rigs wireless 132

TECH TRENDS 134INTERNATIONAL HIGHLIGHTS 140ON THE MOVE/INDEX TO ADVERTISERS 142-143

LAST WORDSetting course for a polar-class drillship 144

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, 2013. 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.

DEPARTMENTS AND COMMENTARY

COMING NEXT MONTH The June issue of E&P takes an in-depth look into the growing complex-ity of well completions technology. Other features will examine how to improve exploration success as well

as the latest advancements in land seismic; deepwater rig advances; sand, proppant, and fluid man-

agement; and topsides solutions. Regional reports will feature the Permian basin and China. As always,

while you’re waiting for the next copy of E&P , remember to visit EPMag.com for news, industry updates,

and unique industry analysis.

Printed onrecycled paper

ABOUT THE COVER Deepwater represents the future for the offshore sector,but every step forward reveals new risks and challenges. Left, the US Gulf of Mexico

is enjoying a spectacular resurgence three years after Macondo. (Main cover

image courtesy of Trelleborg; cover design by Laura J. Williams)

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ONLINE CONTENT MAY 2013

PREMIUM CONTENT Subscribe @ EPmag.com/explorationhighlights

AVAILABLE ONLY ONLINE

Kenya plans to adopt competitivebidding for June oil licensing roundBy Obafemi Oredein, Special to E&PExploration success in Kenya is attract-ing international interest, but new regu-lation governing licensing rounds iscausing concern.

Myanmar opens door to foreign playersBy Steve Hamlen, Special to E&POffshore opportunities await foreign investorsafter Myanmar authorities lifted a local partner-ship requirement.

Tech issues, shale gas could impactFLNG ordersBy Velda Addison, Associate Online EditorBased on the number of potential projectsbeing planned, eight floating LNG (FLNG) orders could be placedbetween 2013 and 2017, according to a recently released report.

Anadarko’s massive oil findcould bring in billionsBy Darren Barbee, Hart Energy

Analysts believe the deepwater Gulf of Mexicodiscovery could double the resource potentialof the Shenandoah basin to 600 MMbbl of oil.

Hyundai wins $2 billion Moho Nord FPU, TLP contractsHyundai Heavy Industries received two contracts valued at US $1.3 bil-lion and $700 million to build a floating production unit (FPU) and ten-sion-leg platform (TLP), respectively, for Total E&P Congo’s Moho Norddeepwater development offshore Republic of the Congo, Hyundaisaid in a press release.

SBM seals $3.5 billion Lula FPSO dealSBM Offshore has received a letter of intent for the 20-year charter andoperation of two FPSO vessels for the deepwater Lula field offshoreBrazil, with the value of the dual-floater deal put at US $3.5 billion, thecompany said in a press release.

BP, partners approve Clair appraisal program in North SeaBP and its co-venturers Shell, ConocoPhillips, and Chevron announced in

a press release their decision to proceed with a two-year appraisal pro-gram to look at the possibility of developing a third phase of the Clairfield west of the Shetland Islands in the North Sea.

R E AD T H E L AT E S T E P m a g .c o m I N D U S T R Y N E W S

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Golf, anyone?Water will be cleaner and golf courses greenerthanks to water management technology.

This is technology transfer at its finest. Our “operator solutions” featurethis month focuses on water management, particularly the difficulty intreating produced and flowback fluid in drilling, fracturing, and production.But one company’s efforts in oil and gas seem to be so successful that it istaking its concept to a more relaxed venue.

STW Resources Holding Co. has announced that it is implementingits desalination system at the Ranchland Hills Golf Club near Midland,Texas, converting 700,000 gal/d of brackish water into rainwater-qualityirrigation water.

That’s right – West Texas golfers can enjoy their lush greens and fairwaysknowing that they have the oil and gas industry to thank for their little patch

of heaven.Turns out the golf course sources its water from 550-m (1,800-ft) wells pro-ducing from the Santa Rosa aquifer beneath the freshwater aquifer used by the local municipalities and water well owners. Prior to the desalinationefforts, the course was spending considerable amounts of money on chemi-cals to prevent the salt from harming the grass.

The system is slightly modified from STW’s oilfield application sincesalinity is not the primary concern in oil and gas fields. Oilfield applicationsare applied to produced and flowback water and are designed to remove con-taminants from the fluid stream. But a simple modification to the system at Ranchland Hills means that some minerals have to be added back in to keepthe purified water from being too corrosive.

Not surprisingly, STW is looking to expand its nonoilfield capabilities to work on a large scale for cities and industries. Stanley Weiner, CEO, said ina press release that the company is in negotiations with certain municipali-ties. “We believe that the STW system can operate at a per-gallon cost that iscomparable to the cost that most municipalities are currently being charged,”he said.

With so much hue and cry about fracturing operations and the potentialimpact on freshwater aquifers, it is heartening to seethings go the other way – to see the strides that arebeing made in water management in the oil patchtest their usefulness in different industries with thesame basic problems.

As ISEE IT

1616 S. VOSS ROAD, STE 1000HOUSTON, TEXAS 77057

P: +1 713.260.6400 F: +1 713.840.0923www.EPmag.com

Read more commentary atEPmag.com

RHONDA DUEYExecutive [email protected]

Executive Editor RHONDA DUEY

Group Managing Editor JO ANN DAVY

Senior Editor, Drilling SCOTT WEEDEN

Senior Editor, Offshore MARK THOMAS

Senior Editor, Production JENNIFER PRESLEY

Chief Technical Director,Upstream RICHARD MASON

Associate Managing Editor MARY HOGAN

Associate Online Editor VELDA ADDISON

Assistant Editor CODY ÖZCAN

Corporate Art Director ALEXA SANDERS

Senior Graphic Designer LAURA J. WILLIAMS

Production Director JO LYNNE POOL

Reprint & PDF Sales ERIC MCINTOSH

Director of Business Development ERIC ROTH

Group Publisher RUSSELL LAAS

Editorial Advisory Board

CHRIS BARTONSr. VP Business Development, Oil & Gas, KBR

KEVIN BRADYPresident, Multi Products Company

MIKE FORREST

Exploration Consultant, formerly with ShellJOHN M. GILMORE JR.

Director of Global Industry Solutions UpstreamOil & Gas, Invensys Operations Management

CHRIS JOHNSTONVP & Managing Director, North America, Ensco

ULISSES T. MELLOManager, Petroleum & Energy Analytics, IBM

DONALD PAULExecutive Director, University of

Southern California Energy InstituteEVE SPRUNT

Business Development Manager,Chevron Energy Technology Co.

MANUEL TERRANOVASr. VP Regional Operations & Global Sales,

Drilling & Production, GE Oil & GasRONNIE WITHERSPOON

President,Superior Well Services, a Nabors company

DENNIS A. YANCHAKSr. Geosciences Advisor, Apache Corp.

Editorial DirectorPEGGY WILLIAMS

President & Chief Operating OfficerKEVIN F. HIGGINS

Chief Executive Officer

RICHARD A. EICHLER

7

H A RT S ERGY

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P reparations are under way for a referendum on inde-pendence for Scotland to be held in late 2014. Thelegal implications for the UK oil and gas industry of an

independent Scotland can be expected to take centerstage in the debate. The prospect of an independent Scotland raises a whole range of complex and unprece-dented legal issues, both domestically and internationally.

Domestic legal implicationsRegardless of whether one views the ultimate outcome of independence as positive or negative, it is inevitable that independence would lead to a period of uncertainty untilthe regulatory regime applicable in Scotland becameclear. A vote for independence would trigger the negotia-tion of an independence statute or treaty. To avoid a legal

vacuum, in previous cases the independence statute hasprovided that, with exceptions, all Westminster legislationin force immediately before independence should con-tinue in force unless and until repealed by the legislatureof the newly independent state. The UK Petroleum Act of 1998 and licenses issued under it would therefore be likely to continue to apply unless and until the Scottish govern-ment chose to alter them. However, particular issues

would arise regarding the transfer of rights and obliga-tions in relation to those licenses (and in particular, pro-ducing fields) that straddled any putative delimitation linebetween the UK and a new Scottish state.

For those cross-border fields a new treaty would berequired between the UK and Scotland similar to theexisting UK/ Norway treaty addressing issues suchas jurisdiction, consenting, HSE standards, and decom-missioning. A double taxation treaty between the twonations would also be required. While these were beingnegotiated, investment in cross-border fields wouldlikely be inhibited.

A new Scottish administration would presumablynot wish to unsettle the industry by making precipitatechanges to regulation; indeed, Scottish National Party (SNP) ministers have stated that no changes in the fiscal

regime would be made without consultation. However,given statements from SNP ministers about the signifi-cance and potential of the oil and gas industry for theScottish economy, a new Scottish government might indue course seek to increase obligations on operatorsthough license terms or the tax system. Any uncertainty as to future policy in this area could have a significant chilling effect on investment.

Critical in this respect would be clarity with respect totax relief on decommissioning of infrastructure. A two-

year consultation process between industry and govern-ment leaders is due to culminate in the introduction of a

finance bill addressing the necessary legislative changesto allow the UK government to issue decommissioningrelief deeds and provide certainty on tax relief. However,many of the more expensive installations to be decommis-sioned in future years are in the Scottish sector. The SNPhas indicated that it supports this project and wouldhonor the deeds, but this would be subject to the negotia-tion of an agreement with Westminster regarding thesharing of the liability. A successful outcome to this nego-tiation would be critical to avoid a return to pretax secu-rity (which in turn could trigger defaults under security agreements) and possibly premature decommissioning.

If Scotland gains its independence in 2014, the move could

have significant impacts on the offshore industry.

May 2013 | EPmag.com 8

industryPULSE

Legal implications

of an independent ScotlandThe country’s independence could result in a host of issues facing the offshore oiland gas industry.

Pieter Bekker and Penelope Warne ,Steptoe and Johnson

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One urgent task for an incoming administration wouldbe to replicate the various UK regulatory bodies, such as

the Department of Energy and Climate Control and theHealth and Safety Executive, which likely would requiresignificant additional recruitment. Recruitment is a chal-lenge for these regulators today given that they competefor staff with a high-paying industry. There would be thepotential for a significant chilling effect as a new adminis-tration struggled to find the staff to address matters suchas license applications, transfers, drilling consents, safety cases, and the like.

International law implicationsThe prospect of Scottish independence also raises a wide

variety of international law issues. The international com-munity can be expected to treat the remainder of the UK as succeeding to the UK’s treaty rights and obligations,including the constituent treaties of international organi-

zations of which the UK is a member. The question of Scottish membership of such organizations is primarily governed by the rules concerning acquisition of member-ship and any other relevant rules of the organization con-cerned. As regards EU membership, Scottish secessionfrom the UK, which is an EU member state, would triggeran unprecedented situation – one that is not expressly foreseen within the EU legal framework. As a result, theprocedure for Scottish accession to the EU could be cum-bersome. The rest of the UK can be expected to remaina member of the United Nations and its 16 specializedagencies – including the international financial institu-

tions. Scotland would have to apply for membership insuch bodies, similar to the situation that South Sudan

faced after it seceded from the Republic of the Sudanfollowing an independence referendum in January 2011.

Scottish independence would affect the status of thenearly 14,000 treaties, multilateral and bilateral, currently in force for the UK, including Scotland. In accordance

with the rule of nontransmissibility and similar to SouthSudan, an independent Scotland would not automatically be a party to such treaties except if they define boundariesor contain rules that are generally accepted as declaratory of general international law (such rules would continue tobind a new Scottish state). As regards offshore oil and gasproduction, the rule of nontransmissibility raises particu-

lar issues under the UN Convention on the Law of the Seaand the Convention for the Protection of the Marine Envi-ronment of the Northeast Atlantic, both of which addressliabilities arising from decommissioning of offshore instal-lations and the maintenance of pipelines.

Where to draw the boundaries? An independent Scotland would need to agree to itsboundaries with the rest of the UK in accordance withinternational law. Any boundary treaties in force for theUK would bind an independent Scotland. An independent Scottish government and Westminster can be expected to

advance competing maritime claims affecting licensedareas in the North Sea, while the western boundary wouldpresent its own complexities. If the Orkney Islands or theShetland Islands did not join an independent Scotland,the resulting situation would greatly complicate the post-independence boundaries.

Assuming an independent Scotland and Westminster would consent to having the International Court of Jus-tice (ICJ) decide the course of their disputed boundary,ICJ boundary cases have taken at least three, and some-times more than 10, years to conclude – resulting inuncertainty in the intervening period. In drawing the

Anglo-Scottish maritime boundary based on internationallaw, a competent court or tribunal is likely to apply theequidistance method, which if strictly applied wouldresult in a line that cuts through licensed areas and favors

Westminster in the North Sea given the geographical con-figuration of the relevant coast. While Edinburgh and

Westminster could, alternatively, agree to create a joint development zone or international unitization in theNorth Sea as the UK and Norway have done, it is not cer-tain that an arrangement that is workable and sufficient to convince existing investors not to abandon their blocksis feasible in the Anglo-Scottish case.

Depending on the boundaries that are agreed upon if Scotland

becomes independent, some operations might straddle those

boundaries. (Image courtesy of BP)

industryPULSE

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The solution to the world' s carbon challenge seems daunting; as the world grows , so does thedemand for fossil fuels.

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Growing groundsfor optimism in UK watersWith the UK offshore sector set for a period of record investment, one of the country’s leadingoil industry figures says optimism remains strong for the industry going forward, both in itshome waters and abroad.

A ccording to the oil and gas industry’s representativebody Oil & Gas UK in its latest annual survey,nearly US $150 billion is embedded in operators’

plans for exploration, development, and productionprojects on the UK Continental Shelf (UKCS). As the highest forecast investment level for more than

30 years, this is largely due to the industry responding torecent growth-focused tax changes by the government, with nearly $20 billion forecast to be spent this year alone.

Malcolm Webb, the CEO of Oil & Gas UK, is currently acting as chairman of the biennial SPE Offshore Europe2013 conference and exhibition in Aberdeen, Scotland,due to take place in September.

Webb, a lawyer by profession, has been involved in theUK sector since the 1970s when he worked at BurmahOil, later holding roles for the British National OilCorp., Charterhouse Petroleum, and PetroFina before

joining Oil & Gas UK in 2004. As a result, he has seenboth good and bad times in the North Sea and further

afield, but right now he is in a positive mood.

Challenges“I’m definitely more optimistic now,” Webb said. “Wehave a range of challenges in front of us – the discover-ies are getting smaller, the water is getting deeper, andthe reservoirs are getting more complex.

“But at the same time the UK government under-stands the situation and has recently given us certainty over the treatment of decommissioning assets. It has put in place allowances that give incentives for people andcompanies to invest here.”

He highlighted recent major projects that have beengiven the go-ahead by operators and approved by theUK authorities, such as Statoil’s Mariner field in the UK sector. This heavy oil field will see an estimated $7 bil-lion invested and is the sector’s largest offshore develop-ment in more than a decade.

$7 billion Mariner projectMariner was discovered in 1982, but production wasdelayed due to technical challenges in extracting theheavy oil. It also was delayed due to Statoil’s decision tosuspend activity two years ago when the UK government,

without warning, suddenly raised supplementary charges in 2011 with a windfall tax. The operator only restarted progress after an industry uproar (from enti-ties including Oil & Gas UK) quickly led politicians torethink their plans and offer tax breaks such as the RingFence Expenditure Supplement for marginal fields.

“The government does now get it,” Webb said. “They are with us, and they understand the importance of theproduct. Oil and gas supplies around three quarters of the energy that this country uses, and the DECC [Depart-ment of Energy and Climate Control] says it will stay higher than 70% until into the 2040s.”

Malcolm Webb serves as CEO of Oil & Gas UK. (Image courtesyof Oil & Gas UK)

Mark Thomas , Senior Editor, Offshore

worldVIEW

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He also praised the government’s “groundbreakingcommitment” to provide certainty on decommissioningtax relief, which has now prompted global companies and

independent businesses to take a fresh look at the UK off-shore sector as an investment destination. This already hasresulted in a new wave of investment. “It is crucial that wesustain this momentum in the years ahead,” he said.

Webb added that there must be “a national imperativeto maximize production” and that the industry hasresponded already. “We think we are going to see agrowth in production. But we are still leaving more oil inplace than we produce, so that is an issue that continuesto require continued attention.”

Offshore EuropeThat brought Webb on to the Offshore Europe confer-

ence. The show, which will mark its 40th anniversary this year, is now recognized as a global platform for theupstream industry and is much changed from its early North Sea-focused roots.

“We have leading speakers from within the industry,the government, and other stakeholders, and we are very much looking ahead, which is why the overall theme is‘the next 50 years.’ It’s extremely significant that theUKCS will see a record capital spend this year. Theindustry is very much alive.”

He described the strong resurgence in activity asclear evidence that the offshore industry has an impor-

tant future ahead of it, “with planned projects wealready know about spanning the next 50 years.”

According to Oil & Gas UK’s survey of its 40-plus mem-

bers, those projects include eight lying west of Shetland,23 in the central North Sea, 13 in the northern NorthSea, and six in the southern North Sea or Irish Sea.These potential new developments comprise 2.9 Bboeof recoverable reserves.

However, great opportunities also bring great chal-lenges, with the Offshore Europe conference sessions set to embrace commercial, employment, operational, safety,and environmental aspects as well as the policy and regu-latory framework in which the industry operates. “This

will be the definitive event for our industry as it movesthrough the 21st century,” Webb said.

The energy mixSubjects covered by various panel sessions include therole of oil and gas in the future energy mix, North Seadrilling and industry progress since Macondo, technol-ogy, and decommissioning. The energy mix session willbe particularly wide-ranging, covering the global energy outlook, the future of transport fuels, the unconventionalgas revolution in the US, and a look forward at unconven-tionals in Europe. It also will address the role of technol-ogy and partnerships in the future of the Europeanoffshore oil and gas industry.

The session on Macondo will review the reactive andregulatory initiatives that have emerged since the tragicincident in 2010. The oil and gas industry in the US,UK, and around the world has carried out a significant number of investigations, reviews, and initiatives toaddress findings from the incident and prevent any future recurrences of this scale and nature. Webbpointed out how the preventive initiatives taken bycompanies, cross-industry bodies, and regulators haveresulted in the development of high-quality operationalguidelines and procedures.

“We are seeking to raise the profile of the industry

and the event as a whole. Several surveys have consis-tently shown that the public thinks the UK now importsthe majority of its energy. We need to correct that per-ception,” he added. “We have an internationally renowned supply-chain spread right across the UK –there are more than 30,000 jobs offshore but around440,000 in the support infrastructure. If our supply chain is going to prosper, it has to compete and performagainst the best in the world. The UK has an outstand-ing reputation as a global center of excellence, with aleadership role in areas such as subsea, and this will beevident at the event.”

worldVIEW

Statoil’s $7 billion Mariner development got the go-ahead earlierthis year, heralding a new period of record investment for the UKoffshore sector, where nearly $20 billion is forecast to be spentthis year alone. (Image courtesy of Statoil)

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U pstream oil and gas operators are increasingly chal-lenged to maintain the appropriate level of technicalexpertise to operate their assets in an optimized way. Sea-soned engineers retire or change positions or employer.

As routine work has gotten mostly replaced by computers,the human input into processes is getting more and morecomplex. Hence, losing people means losing knowledge.

The industry’s proprietary technical and business software applications enable neither knowledge capture norownership and intellectual property over the operator’s

workflow solutions. Organizations still struggle to come up with a software landscape that enables the effective pro-cessing of cross workflows that go beyond the borders of adepartment or a technical discipline. This landscape of isolated software silos impedes scalable system integration;thus information technology departments struggle to

implement service-oriented architecture.Nevertheless, well and reservoir surveillance software

solutions able to detect unfavorable operational settingsand identify underperforming wells are available on themarket. But to improve decision-making in asset opera-tions, expert or advisory systems representing industry and operator’s best practices are needed.

Improved decision-making in asset operationsOperations in oil and gas fields are typically driven by theobjective to maximize ultimate recovery or the recovery toa certain date. Production losses mean that a significant

amount of money is left on the table. Hence, deferredproduction or underperformance must be detected assoon as possible after occurrence (or ideally even beforeeither occurs). An activity needs to be initiated immedi-ately to reduce the amount of lost production or to avoidany losses at all.

With regard to producing hydrocarbons in an opti-mized fashion, there are four main steps in related deci-sion-making processes:

Free to focus: Data screening (e.g. pattern recognitionenabled by special visualization and data mining) is usedto identify symptoms that indicate that asset performance

is not as good as expected. Patterns among wells aredetected to identify similar behavior and reduce the com-plexity of the screening problem from several hundredsensors to a few categories of similar measurement types.

Truly understand the challenge: Petrotechnical analysismethods (e.g. sensitivity analysis on numerical or analyti-cal models) are applied to identify the root cause of why the performance is below expectation. The objective is toidentify the constraint, such as whether the liquid produc-tion is limited by reservoir deliverability, well production

potential, or facility processing limits. Due to the ambigu-ity of some of the symptoms as identified in the first step,the outcome of this step will be probabilistic, indicatingmost likely causes but also possible alternative causes.

Improve decisions: Based on a definition of utility (e.g.maximize production, minimize losses, increase net pres-ent value, reduce lost time, etc.) decisions are suggested tosolve the problems as identified in the first two steps. Pre-

vious experience from the same reservoir, similar situa-tions in other reservoirs, or information from case studiesare the sources needed to select the most promisingaction with regard to the utility given the constraint as

Knowledge layer is

next ‘big innovation’The upstream industry is losing knowledge every day. A new approach helps operatorscapture knowledge and build adaptive advisory systems.

Michael Studner , Myrconn Solutions

FIGURE 1. The adaptive advisory system captures knowledge

from experts and experiences to provide a framework for an

intensive knowledge exchange. (Images courtesy of MyrconnSolutions)

managementREPORT

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identified above. A definite selec-

tion will not be possible in thisstep. Therefore, the suggestion

will be of probabilistic nature.Increase knowledge: The impact

of the actions resulting from thedecisions in the third step is ana-lyzed and verified. Did the action yieldthe expected results, or is the perform-ance different from what is expected? Thediscrepancy between the expectation and theactual observation is the learning opportunity,

which needs to be recorded, explained, and finally

generalized to clearly identify whether or not this particu-lar piece of information is applicable to a single situation,the whole field, or the whole company. The gained knowl-edge is stored and updated in the knowledge layer forfuture application.

The adaptive advisory systemThere is a business need to detect events such as severeunderperformance in the asset and to react properly andin as timely a fashion as possible to keep production up totarget. When combined with the incomplete and uncer-tain information available from the sensors in the facilities

and wells, this can lead to the fact that operations are very often cases of firefighting and rushing from one event tothe next.

Actions are usually taken reactively after a certain event has been observed. Moreover, the actions that are consid-ered after a certain event has been detected often are not based on the full amount of technical expertise availableto an oil and gas producing organization at a current timebut rather on typical approaches and rules of thumb that have been around in an organization for ages.

The standardization of processes, common perform-ance metrics, reporting, and documentation is hardly ever

in place. Hence, it becomes difficult for an organizationto monitor and support its producing assets and almost impossible for it to efficiently share information fromone organizational unit to the next.

The adaptive advisory system is designed for an inten-sive interaction. It captures knowledge from experts andexperiences and at the same time provides a frameworkfor an intensive knowledge exchange of engineers,experts, and managers (Figure 1). It facilitates the asset team in decision-making processes and helps to fileknowledge in a way that makes it accessible in futuretimes as well as to other units.

Investigating the root cause of eventsinvolves further analysis of the availableevidence and possibly the request of additional evidence. The outcome of the root cause investigation is a defini-

tion of the problem that has occurred in the asset. There-

fore, it is a very analytical step where the user is requestedto interact with the system and the data to confirm andinvestigate the root causes that led to the event.

A Bayesian network-based expert systemTo set up a problem classification advisory system, theexpert system can either be trained using historical event data or, where no sufficient historical data are available,the network structures and according probabilities can bedetermined by experts.

An example of root cause identification using aBayesian network is displayed in Figure 2. The most

likely root cause for declining pump performance isdetermined based on the Bayesian network taking intoaccount the observations and real-time measurements.The observations can be independent (e.g. pump ageand reservoir pressure) but also can be linked by a causalrelationship (e.g. wellhead pressure and productionrates). The example shows that given the informationabout the pump, reservoir, and fluid and measuringdropping liquid rates and wellhead pressures, the most likely cause is gas ingestion. However, mechanical prob-lems and possible excessive pump wear (e.g. due to sandin the pump) should not be entirely excluded.

The added valueThe knowledge layer approach helps operators overcomethe dilemma of permanently losing knowledge by captur-ing it and building adaptive advisory systems. True added

value is gained when a knowledge layer is incorporatedin collaboration portals and business process manage-ment systems. Decisions will be continuously improved,and the advisory systems become increasingly more solid

with a growing knowledge base.

References available.


FIGURE 2. A Bayesian analysis factors

in many datapoints to determine the

most likely cause for declining pump

performance.

managementREPORT

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W hen compared to conventional plays, unconven-tional resources were traditionally seen asuneconomic since they require some sort of artificial

stimulation (such as hydraulic fracturing) or lift (steaminduction) to sufficiently increase the mobility of thehydrocarbon fluids. But with the advent of higher fuelprices and technological advances, many of these playsare now economic.

The greatest expansion of unconventional play activity has occurred within the US in the Barnett, Eagle Ford,and Bakken plays. Huge oil reserve figures have beenquoted for those plays, which could total up to 30 Bbbl.

These forecasts have attracted not only US energy compa-nies but also international and multinational companies.

Brittle reservoirsBoth the Barnett and Eagle Ford reservoirs have apropensity for brittleness, which can make them

susceptible to fracturing. It should thus be no surprisethat the industry has focused on predicting areas of potentially increased permeability due to the presenceof natural fracturing that may then be enhanced withhydraulic fracturing.

The current methodology is to identify these sweet spots and optimize production with intense horizontaldrilling and hydraulic fracturing. Wells and sometimesconventional seismic are commonly used when predict-

ing rock properties to determine the trend of maximum stress and then define the wellborepath to facilitate hydraulic fracturing. Some

companies also are acquiring microseismic dataat their wellbores for more direct measurementsof anisotropic rock properties, while others aremostly identifying zones of increased brittlenessto drill in between existing wells. In the Barnett shale, for example, the net result for these work-flows has been commonly reported as 80% of the production from 30% of the completions.

Reservoir complexity Why do 70% of the completions fail to signifi-cantly contribute to production? First, the well-

bore may not be optimally positioned at anappropriate angle to regional stresses. This may be a result of inaccurate rock property calcula-tion and mapping or complex structural fabricoverprinted by several regional events. Addition-ally, the structures of interest – fractures andsmall faults or facies changes – are sub-seismicand cannot be delineated from conventionalseismic using conventional processing. Finally,in the case where only wells are used for delin-eation, the underlying assumption is that rockproperty information can be carried between


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Unconventionals require

nontraditional workflowsSubtle heterogeneities in unconventional plays require the use of rigorous processing,imaging, inversion, interpretation, and reservoir modeling.

Bruno de Ribet , Paradigm

FIGURE 1. A full-azimuth seismic-driven reservoir characterization was per-

formed from a full-azimuth acquisition in the Eagle Ford shale. (Data in

upper left image courtesy of Seitel; images courtesy of Paradigm)

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the wells. The problem with looking at an extensiveshale formation and pursuing a simple infill programis that these reservoirs are not isotropic or homogenous.

The actual reservoirs, like in the Eagle Ford, can bethe result of drastic facies changes, and the rock proper-ties are complex. To create models that are accurateand successfully predictive, a more rigorous approachis required.

Reservoir characterizationEnhanced-performance technology and tools designedto facilitate accurate reservoir characterization haverecently become available. These provide solutionsfor unconventional play types with an integrated andmultidomain approach across the entire workflow, from

full-azimuth processing and imaging to reservoir engi-neering, to reduce uncertainties in the decision-making,planning, drilling, and completion process.

Despite the challenge of vertical resolution, conven-tional seismic data offer valuable information regardinglithology, fluid content, and in situ stress events. For theaccurate extraction of rock properties from seismic data

without azimuthal biasing, a new full-azimuth angledomain imaging and analysis technology has beendesigned to deliver unsectored data for subsurface

velocities, structural attributes, rock and fluid proper-ties, and reservoir characteristics. As this process pro-

vides in situ recovery of continuous azimuth and angleprestack data in depth, additional information fromboth modern and legacy seismic data (especially wide-and rich-azimuth data with long offsets) is produced. Inlow-permeability and fracture system plays this technol-ogy, with its solutions for anisotropic tomography, pro-

vides stress and fracture detection for accurate reservoircharacterization correlating to shale properties.

In a case study of the Eagle Ford formation full-azimuth reflection angle gathers for a 36° opening angleare shown in Figure 1. The accompanying minimum-stress fracture orientation map with measured intensity

overlies the most apparent brittle zones shown in rain-bow colors. To map the spatial distribution of the esti-mated highest brittleness material (vs. ductile), thederived seismic attributes, Poisson’s ratio, and Young’smodulus were calculated from a simultaneous inversionand analyzed through advanced cross-plotting for geo-body detection and mapping.

Interpreting seismic attributes through enhanced visu-alization, such as advanced merge methods or opacity, lay-ering, and interactive cross-plot techniques, provides amore precise reservoir characterization, enhancing pre-dictions of the spatial conditions of trapping systems and

the distribution of subsurface lithology and reservoirproperties. New, highly parallelized compute power capa-bilities provided by graphics processing units to perform

computations traditionally handled by central processingunit power were first adapted for improved visualization.They also can be used for on-the-fly calculations to extract post-stack information such as frequency-dependent attributes that can efficiently contribute to an interpreta-tion workflow. With proper calibration to in situ condi-tions observed at the wells, trends can be identified andmapped for sweet spot determination.

Information from log evaluation can be used to auto-matically calculate a predictive model directly or can becombined with the structural interpretation for a moreintegrated approach.

Unconventional plays have poor reservoir propertiesand are difficult to interpret with seismic data. This may

be due to the negligible acoustic impedance contrast;the presence of gas, which degrades compressional waveimaging; or multiple stress episodes. The challenge iseven more complex in the presence of faults reactivatedafter the time of deposition. A proportional reservoir topand base slice extraction is certainly the best approach forunderstanding the seismic stratigraphy if the depositionalsequence is not complicated by progradation or tectonicevents within the interpreted seismic zone. If there isfaulting or any internal variation of the sediment deposi-tional sequence, however, this approach will lead to anerroneous geologic interpretation.


FIGURE 2. A seismic facies map paired with curvature attributes

highlights the heterogeneities of the shale and suggests areas

of possible increased fracturing within the Eagle Ford reservoir.

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To avoid such bias, the interpretation should be validated in the paleogeographic (geochronological)sense at the time of deposition with a change of refer-

ence from X, Y, and Z to U, V, and T, where T is the geo-logic time and U and V are the paleo-coordinates. Thistransform enables flattening in the UVT space of boththe interpretation and seismic data and helps the inter-preter understand the relationship between geologicalevents and validate the structural interpretation.

Through waveform seismic facies classification, seis-mic data can reveal the extreme heterogeneity that char-acterizes unconventional reservoirs. This techniqueleads to an understanding of the seismic response vari-ability within the reservoir. The correlation at the welllocation helps illustrate the relationship between local

and large-scale homogeneous patterns to reveal hetero-geneities distribution (Figure 2).

The combination of interpretation, characterization,and reservoir modeling leads to better control of drillingrisk. By integrating all the information in a 3-D canvas,

potential hazards can be identified and mitigated. Usingautomated fault-enhanced extraction, the interpreter canextract lineaments along horizontal and vertical slices at

the discontinuities (along fault planes) and link theminto fault planes. The ability to investigate both the linea-ments and the discontinuities associated with them canprovide insight into potential zones of enhanced fractur-ing/permeability vs. areas of permeability boundaries.

Producing hydrocarbons economically from low-per-meability unconventional plays drives the need for wellpath and engineering design optimization at every stageof the planning and drilling process. The subtle natureof fracturing and facies changes in unconventional playsrequires the use of rigorous full-azimuth seismic process-ing, imaging, inversion, interpretation, and reservoir

modeling. Designing wells within a 3-D structural modelthat integrates all relevant features can shorten well-planning cycle times, improve well placement, andreduce drilling risk while facilitating the decision-mak-ing process.

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The combination of horizontal drilling and hydraulicfracturing technology has put the US on track tobecome a top energy producer.

Industry estimates have each new well requiring 1,000

or more truck trips to transport materials like gravel andpipe, equipment, and water and to haul off wastewater,among other services. A recent study by the New YorkState Department of Environmental Conservation esti-mated between 5,850 and 8,905 upstream truck trips wereneeded for a multiwell pad based on two rigs and equip-ment deliveries for eight wells.

Energy development activity in the US and Canada hasbeen a shot in the arm for the trucking industry, poweringa recent boom in truck sales – many now with automatictransmissions – and attendant growth in well service fleetsalong with increased demand for more general commer-

cial trucking services.

Unusual driver demandsTransporting fuel, pipe, drilling equipment, sand, water,and other materials to and from a well site is a small frac-tion of total preproduction costs but generates an outsizednumber of business transactions in the process. Rapidfleet expansion and increased trucking activity in generalare overwhelming the system capabilities of many firms tostay on top of wellsite demands and fleet resource alloca-tion, not to mention billing.

A business with 20 to 25 trucks may now be expanding

fleet size to 200 trucks or more in less than a year, only tofind that its manual business procedures have been unableto scale. Hiring more office workers to manage paper jobtickets and invoice production is the common response,but the opportunities for error increase with the volumeof orders handled manually.

Both preproduction and post-production wellsite opera-tions present logistics and scheduling challenges for trans-portation providers and their drivers.

In addition to logging their arrival and departure times,drivers record trailer tank levels on field tickets. Levels aremeasured using dipsticks before and after loading crude

oil. With any delay in routing paperwork, oil may be deliv-ered to a pipeline or refinery before customers even get quantity data.

When loading condensate at gas wells, drivers must fur-ther check wind direction, open collection tanks, and usespecialized equipment to collect samples and conduct analyses for specific gravity and water content that also iscaptured on job tickets.

Environmental compliance is another record-keepingconcern, especially with regard to the disposal of waste-

water. The importance that oil companies put on trackingsafety ratings for drivers and for-hire carriers adds addi-tional reporting burdens on service providers.

Paper job or field run tickets are the primary means totrack service hours and details, but their handling – or mis-

handling – is one of the major causes of inaccurate ordelayed billing and customer invoice disputes.

Technology fills the information voidTransportation management systems (TMS) are designedto make complex logistics challenges simpler. Some aretrue business operations systems, integrating fleet man-agement and visibility with customer service and billing tocover the entire quote-to-cash business process.

TMWSuite is a TMS that can increase productivityfrom fleet assets and lead to faster service response time tocustomers in the North American oil and gas industry.


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Bringing transportation management

to the oil and gas industryDemand for domestic drilling services drives need for smarter fleet management.

Monica Truelsch , TMW Systems

The surge in domestic energy production has created new

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Designed to replace manual, paper-based processes in busy fleet operations, a TMS can drive faster business transactions with theability to integrate global positioning systems (GPS); in-cab wire-

less communications; and smart, digital form management. TheTMS can manage location, service, and billing data for each cus-tomer and well site, which can simplify communications betweendispatch and the driver and lead to the accurate completion of site services and the timely generation and review of invoices.

Vehicle tracking and mobile wireless communications systemssuch as those from PeopleNet Communications Corp. play akey part in fleet management and streamlining business whenused with a TMS.

The level of automation possible with in-cab devices that havethe processing power of small computers can transform the way an oil and gas supplier does business. Using a tracking system

integrated with a TMS, for instance, a driver arriving at an oillease will be presented with the form for the specific serviceneeded. This service requirement can be automatically identi-fied by the GPS coordinates of the truck’s location matchedagainst the TMS data, which can hold coordinates for thou-sands of well sites as well as service order requirements. Dataentry for the driver is kept to the barest minimum because theform pulls any needed location ID and other ticket informationabout the site from the TMS system wirelessly.

The driver fills in beginning and ending dipstick readings.The tracking system, available with an optional mobile printer,spits out receipts for the driver to give to the lease operator. At

the same time, all of the necessary billing information is trans-mitted wirelessly to the home office where the TMS generatesinvoices and the load quantity and quality data before theproduct reaches the pipeline.

The system records delivery details in a similar fashion. Aspart of the process, carriers that haul wastewater can automati-cally track delivery details for environmental reporting compli-ance. Another benefit for energy companies from such anintegrated TMS is the automated reporting and tracking ofaccurate safety data.

When a delivery or pickup is complete, the in-cab tracking sys-tem also can help guide the driver to the next stop with naviga-

tion powered by wellsite-specific GPS and directional data fromservices such as RigData.

Oil and gas E&P has become increasingly more efficientand less costly by embracing new technology wherever possible.Perhaps the next frontier for technology transformation will bethe trucking operations that are so necessary to drilling andproduction activities. TMS and fleet management technologiescan offer industry service providers and commercial carriersmore efficient use and deployment of assets, strategic cost andcapacity insight, instant access to critical information, and sig-nificant reductions in human error in combination withimproved profitability.

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F or the Geophysical Society of Houston (GSH) theSpring Symposium is the premier technical event of the year. The GSH organizes and promotes the event toprovide educational and knowledge-sharing opportunitiesfor its members and the larger geophysical community.

So it is kind of important to “get it right.”Since 2007, the GSH has combined its annual techni-

cal venue with the opportunity to honor a Houston-based geophysicist who has made extraordinary

contributions to the society and the science. “Werethere a geophysical hall of fame, our honorees wouldall be in it,” said Glenn Bear, GSH first vice president.

But finding a ringer was not enough to guarantee acrowd for the two-day event. The organizers also neededa topic and a robust roster of speakers. And, thanks to aformat change that made the event invitation-only tospeakers, they needed the best experts in the business.

Not surprisingly, this year the committee hit on the hot topic du jour – unconventionals. From there it was aneasy step to honor Peter Duncan, founder and CEO of MicroSeismic Inc. Duncan has helped pioneer the use of

microseismic techniques in fracture monitoring and ishelping to expand the technology into other areas as well.

With the honoree and topic chosen, it was time to

invite the speakers. Phil Schultz, first vice president elect,tapped a colleague at Chevron to suggest the moversand shakers within the microseismic cosmos. “He gaveme a good list to work from,” Shultz said. “I pared it down to an ‘A’ list and contacted everyone on that list.”

The result was a two-day program with extremely high-level talks from people who know their stuff. In fact,some of that “stuff” was probably over the heads of tradi-tional geophysicists who have not had much exposure tomicroseismic. But the audience stayed until the end.

A change to this year’s format was to allow a full hourfor each speaker’s presentation, with plenty of time for

discussion at the end. Schultz said that many respon-dents indicated that they learned as much during thesediscussion periods as they did during the presentations.

Also, the presentations were not intended to be adver-tisements. I got the impression that, while microseismicis a great technology that works well in many applica-tions, there are still times that it does not work as wellas one might like, and there are still many mysteries tobe solved.

“Our goal here is to make sure that experts in the fieldsee content that is worth their time and leave with some-thing they didn’t know before,” Bear said. “You will not

attract the experts in any given field if you are having anintroduction to building velocity models or an introduc-tion to microseismic techniques. The technical levelneeds to be pretty high.

“Once the experts have decided that this is worth theirtime, the novices decide they’d better go listen to thecrowd of distinguished speakersbecause the experts havealready forgotten more about microseismic than thenovices know.”

Planets align for local symposiumHonoree, speakers, and topic combine to give a kick to the 2013GSH Spring Symposium.

Read more commentary at

EPmag.com

RHONDA DUEYExecutive Editor

[email protected]

explorationTECHNOLOGY

EPmag.com | May 2013 29

explorationTECHNOLOGY

Microseismic technology has had a rapid uptake due to the

popularity of unconventional plays. (Image courtesy of

MicroSeismic Inc.)

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drilling &COMPLETION

31

The DUG Permian conference in Fort Worth April 2to 4 drew more than 2,500 attendees, showing just how hot a topic the Permian basin is. How do youdrill and complete faster, better, and cheaper wells inthe Delaware and Midland basins to tap the Wolf-camp and Cline formations, for example? It is the

same question that is asked in every unconventionalplay worldwide.Drilling efficiencies have reached the point where

improvements are incremental. A panel of industry experts, however, indicated that there is a lot of roomfor improvement in the technology for unconvention-als. The panel featured Mark Sunderland, southernregion drilling manager, Anadarko Petroleum Corp.;

Jeff Meisenhelder, vice president, unconventionalresources, Schlumberger; Robin Robinson,

vice president, drilling, US land, Baker Hughes; andDanny Williams, vice president, Permian drilling and

completions, Pioneer Natural Resources.“We are drilling 14,000-ft [4,267-m] wells in sevendays or less in the Eagle Ford,” Sunderland said.“What we are looking for is reliability in making alot of hole with existing technology.”

Robinson added that the industry will likely see morepad drilling in the Permian. “With pads there are well-spacing issues, which means more complex pads andbringing in more rotary steerable technology.”

Automation of the rig will be one of the salient tech-nologies moving forward, explained Meisenhelder.“By automation I am not really talking about the safety aspects of it. I am talking about closed-loop feedbacksystems that control weight on bit or wellbore loca-tion. Ultimately, I think we want to control the wholedownhole environment.”

Williams agreed that there would likely be asmany advances in drilling wells. “What we are looking

for is a fluid system that will allow us to eliminatesome of the problems we have in our vertical pro-gram, which also will impact our horizontal workprogram because we drill through the same intervals.

We want to go beyond the standard wash circulationmaterial, stuckpipe events, and all those challenges.

We are looking for ways to tackle these issues without just another casing string. That is a breakthrough weare looking for.”

On the completion side, the industry is focusing onbeing more efficient and effective. Not just in the Per-mian but in other areas of the world, a high percent-

age of perforation clusters do not produce,Meisenhelder said. This is an issue that can be fixed with designed engineering solutions, getting to thepoint of having 100% of the perforations producing.

Tools have been developed that will let operatorssee if the horizontal wellbore is being stimulated effec-tively, Williams continued. “I also agree that stepsneed to be taken to drive efficiency sothat we can do fewer clusters with fewerstages and still achieve the same oreven better production.”

Operators see decades-long

promise of unconventional playsA panel of experts at the DUG Permian conference tackled thetechnology needed to advance drilling and completion efforts.

EPmag.com | May 2013


EPmag.com

SCOTT WEEDENSenior Editor, Drilling

[email protected]

More use of drilling pads will drivefurther development of rotary steerable systems.

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A recent press tour of the Brazilian offshore mar-itime industry gave participants plenty of oppor-tunities to see the enthusiasm and hear the cautiousoptimism of the many companies participating inthe development of the country’s presalt oil andgas resources.

In addition to the ongoing massive offshore devel-opment, the country also is in the throes of a con-struction effort in preparation for its role as host to

the 2014 FIFA World Cup and the 2016 SummerOlympics. A comment that I heard often during thetour was, “All eyes will be on Brazil in a few short

years, and we will be ready to shine.”The comment sounded a bit odd since Brazil has

held, in some circles, the world’s attentionfor quite some time. The discovery of presalt resources in the Tupi field(now the Lula field) in theSantos basin in 2006,followed by discoveriesin the Campos basin,

captured that attention.The rapid-fire pace of exploration and fielddevelopment has kept industry interested asit waits to see how thetechnical challenges of production and trans-portation will be tackled.

In 2012 Petrobraskicked off a Carnival-esqueparade when the FPSO vesselCidade de Anchieta , the first of 39new production units planned forstartup between 2012 and 2020, arrived onlocation in the Baleia Azul field. Of those 39 units 25

will start up between 2013 and 2017. The next few years are going to be very busy for Brazil.

As development efforts samba farther and deeperinto the offshore, it becomes more crucial that operat-ing standards can keep up with the pace. One area of concern – pipeline safety in extremly deep water –prompted DNV to assemble a joint industry project

(JIP) to capture more knowledge on how pipelinescan safely withstand the pressures of 3,000-m (9,843-ft) water depth without prohibitive cost.

In an announcement about the JIP, DNV said that 65% of the world’s offshore pipelines are designed

and installed to its pipeline standard. The JIPaims to research and explore, with input

from relevant companies throughout a variety of industries, the optimal bal-

ance between feasibility, safety,and cost.

“We are in the phase where

the objectives are clear andthe systematics are in place,but we want to capture moreknowledge and experience,”

Ana Paula Franca de Souza,manager of the JIP, said onbehalf of DNV. According to a press

release, the JIP is immediately relevant for the extreme condi-

tions facing the industry in Brazil’spresalt fields, and advances in opti-

mization of pipelines will be welcomedthroughout the industry.“From this joint industry project the recommen-

dations and possible updates to the standard will havefar-reaching consequences, so we welcome broadindustry participation,” de Souza said.

Everyone loves a good parade, and theone marching on in thepresalt will be interestingto watch for years tocome.

EPmag.com | May 2013 33

productionOPTIMIZATION

Carnival comes to the presaltA risk management group invites the industry to work on a standardfor pipelines in extremely deep water.


EPmag.com

JENNIFER PRESLEYSenior Editor, Production

[email protected]

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Listening to a panel of experts recently, it was clearthat the robust growth of the modern floating rigfleet is by no means over. Nearly 190 new floaters areexpected to be delivered between 2008 and year-end2016, with the demands of deepwater drilling now over-

whelmingly favoring modern high-specification units.

Edward Muztafag of Societe Generale, speaking at Quest Offshore’s MCE Deepwater Development event inThe Netherlands, posed the question, “Does the indus-try need more newbuild high-specification floaters? Webelieve the answer is yes, possibly 50 to 70 more over thenext 10 years but at a more steady and protracted pace.”

Identified deepwater drilling and completion demandstill appears to exceed available floating rig capacity by

35 to 50 rigs through year-end 2016, he added.There is no doubt that operator preference has

shifted firmly to new generation high-specification rigspost-Macondo, with these new dynamically positionedfloaters comprising half of the activity worldwide today compared to 20% in 2008.

The knock-on effect is that older generation (legacy)rigs are simply falling out of favor with operators.Muztafag said that a significant number of legacy floaters (second- and third-generation) were cold- or

warm-stacked following Macondo, and “virtually none

of the cold-stacked legacy rigs have found work in thelast two years despite the strong increase in deepwaterdrilling demand.”

Numerous third- and fourth-generation rigs, mean- while, are undergoing significant modifications in anattempt to make them more competitive with newerunits. “The outlook for legacy rigs and some early fourth-generation units is likely facing declining workprospects in the coming years,” he said.

With the average retirement age of floating rigs typi-cally around 30 years, that means that nearly 76 units –comprising 30% of the actively marketed floating rigfleet – are now in their sunset days. A further 15% of actively marketed floaters are between 20 and 30 yearsold, and most can be viewed as “near-legacy” in the next five years.

“A retooling cycle is likely to occur at a more tem-pered pace than the flurries of orders since the mid-2000s, but with nearly 45% of the floating rig fleet upfor possible retirement in the next 10 years, we expect an extended cycle,” Muztafag said.

With the continued growth in global explorationdrilling activity and with operators continuing tofavor high-specification rigs as much of the activity extends into water depths beyond 1,220 m (4,000ft), this shift only places the older legacy units andsome of the fourth-generation rigs at a further signifi-cant disadvantage.

It has been a good run, but timeappears to very suddenly be up for themajority of the offshore industry’saging floating rig workhorses.

35

offshoreADVANCES

Twilight years for a tired fleetWith offshore markets experiencing the biggest wave of newbuild rigorders in more than 20 year

epm-2013-05

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