revista e&p - abril 2011

E P M A G . C O M

Marine seismic

sets sail

A P R I L 2 0 1 1

Subsea Technology

Directional Drilling

Riser Technology

Land Seismic

Improving Exploration

Success

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IMPROVING EXPLORATION SUCCESS

New integrated seismic technology improveswell placement

GGI helps level the playing field forindependents

LAND SEISMIC

Land 3-D seismic survey designed to meet new objectives

Piceance Creek pushes the land seismicenvelope

Geophysical data home in on sweet spot drilling

DIRECTIONAL DRILLING

Geosteering in unconventional shale reservoirs has potential

Bed boundary mapping technology improves success

SUBSEA TECHNOLOGY

Managing the threat of riser gas

Dynamic design tools increase safety

Deepwater production technology gets a boost

RISER TECHNOLOGY

New tool makes riser handling faster and safer

Riser bend stiffener connections prepare to goROV-less

IndustryPULSE:New dynamics ahead for energy, oil

‘It is difficult to make predictions, particularly aboutthe future’ – Niehls Bohr, 20th century Danish physicist.

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

APRIL 2011VOLUME 84 ISSUE 4

A HART ENERGY PUBLICATION www.EPmag.com

COVER STORY

32

Marine seismicsurges ahead Despite two years of setbacks, the marine geophysical sector is poised for busy times.

6

WorldVIEW: Canada invests in technologies to improve oil sands development

John Hofmeister weighs in onNorth America’s energy supply

10

12Unconventional: Bakken

Bakken activity on the riseNew technologies are increasing recovery,

and operators are moving to delineate areas outsidethe core Bakken region.

43

49

53

56

60

65

69

727477

9294

103 REGIONAL REPORT: AUSTRALIA & NEW ZEALAND

83

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AS I SEE IT Change before you have to 5

MANAGEMENT REPORTNew model exists for engineering consulting 16

DIGITAL OIL FIELDThe industry needs next-generation content management 18

New standard streamlines software integration 24

EXPLORATION TECHNOLOGYGeophysicists take on the next ‘grand challenge’ 27

WELL CONSTRUCTION Managing sand from the outset 29

PRODUCTION OPTIMIZATIONThe adventure continues 31

TECH WATCH Fractures detected without shear waves 96

TECH TRENDS Innovations and new releases 100

INTERNATIONAL HIGHLIGHTS Operators display global reach 110

ON THE MOVE/INDEX TO ADVERTISERS 115

LAST WORD R&D needs government boost 116

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 5800, Harlan, IA 51593. Address all non-subscriber correspondence to E&P, 1616 S. Voss Road, Suite 1000, Houston, Texas 77057; Telephone: 713-260-6442. All subscriber inquiries should be addressed to E&P, PO Box 5800, Harlan, IA 51593; Telephone: 713-260-6442 Fax: [email protected] Copyright © Hart Energy Publishing, LP, 2011. Hart Energy Publishing, LP reserves all rights to editorial matter in this magazine. No article may be reproduced or transmitted in whole or in parts by any means without written permission of the publisher, excepting that permission to photocopy is granted to users registered with Copyright Clearance Center/0164-8322/91 $3/$2. Indexed by Applied Science, Technology Index and Engineering IndexInc. Federal copyright law prohibits unauthorized reproduction by any means and imposes fines of up to $25,000 for violations.

DEPARTMENTS AND COMMENTARY

ABOUT THE COVER The satellite image shows the Von Karman vortices offshorethe Canary Islands, collected on June 6, 2010. (Image courtesy of Envisat MERIS, EuropeanSpace Agency, provided by Spatial Energy) In the Gulf of Mexico, a CGGVeritas vesselshoots a wide-azimuth survey. (Image courtesy of CGGVeritas)

COMING NEXT MONTH May E&P features a cover story that brings you expert views on deepwater

challenges and solutions. Additional features present deepwater rig advances, flow assurance and sand and water

management technologies, and ways to extend reservoir life. The offshore regional report spotlights the Gulf of

Mexico, and the unconventional report highlights activity in Horn River. The May issue also presents the winners of

Hart Energy’s Meritorious Awards for Engineering Innovation. An extra plus in this issue is the first installment in a three-

part Special Report on Brazil. While you’re waiting for the next copy of E&P, remember to visit www.epmag.com for

news, industry updates, and unique industry analysis from Richard Mason, online executive editor.

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Anschutz announces Bakken exploratory test resultsThe #1-13-24H-143-97 Raphael Stroh well initially flowed 2,405 b/d ofoil, 421 Mcf/d of gas, and 2,531 b/d of load water. The #1-12-1H-143-97 Kenneth Stroh well flowed 2,409 b/d of oil, 1.42 MMcf/d of gas,and 2,460 b/d of load water.

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MANAGEMENT REPORTNew recruitment strategy removesguesswork in ‘Big Crew Change’ eraBy Bonnie Browning, Q4BBalancing the loss of older skilled talent with the influx of new technical talent hasbecome an unprecedented recruitmentchallenge in the oil and gas industry.

MANAGEMENT REPORTMaking on-the-job training workBy Kara Bennett, Consulting GeoscientistImparting tacit understanding is a big partof a mentor’s job.

Petrobras receives approval for first production from its inauguralFPSO in the Gulf of MexicoBy Peggy Williams, Director, e-ContentBOEMRE gives deepwater Chinook-Cascade production green light.

READ THELATESTEPmag.comINDUSTRY NEWS

Southwest China gas discovery Ivanhoe Energy of Calgary’s China subsidiary,Sunwing Energy, has hit gas with its #2-Yixin well in southwest China, which flowed 9 to 10 MMcf/d.

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Each month, the pages of E&P magazine are full of technology advances thathave resulted from innovation and change – the two primary constants in the

world of engineering.It might surprise some to find out that the same constants hold true in the pub-

lishing world.Hart Energy has been on the cutting edge of many changes in the industry. The

company was one of those that noticed the increasing significance of unconven-tional resources and, in its role as a first mover, developed a conference series focusing on developing unconventional gas and oil that continues to answer anindustry need.

Hart Energy also was on the cutting edge when it came to maximizing its presenceon the web – providing news, information, data, and archives and pushing the limitsof information sharing to include daily news, exclusive editorial, blogs, webinars,podcasts, and videos.

With the addition of Richard Mason in late February 2011 as executive editor forthe online component of E&P at www.epmag.com, Hart Energy once again haspushed ahead of its competitors, offering readers a look at the industry that goesbeyond technology.

Many readers will remember Mason as publisher of The Land Rig Newsletter. From1992 to 2009, he developed the first rig-count metrics involving land drilling activityin unconventional plays to provide a high-resolution perspective on the land drillingmarket, including regional rig use, rig pricing, technological evolution in drillingsystems, and rig employment patterns by operator.

Mason continues to monitor activity with regular exclusive features on the website.As readers of E&P magazine, you can see some of Mason’s observations in “Bakkenactivity on the rise” (page 83) and will have additional opportunities to read hiscommentary in upcoming issues.

While Mason adds depth to our online coverage, Mark Thomas, London-basedinternational editor for E&P, is extending the breadth of the magazine’s interna-tional coverage. Editor at Hart Energy Publishing from 1993 to 2000 and originallaunch editor of E&P magazine, Thomas is no stranger to the industry. You can readhis first installment about Australasia this month in “West coast gas bonanza lightsup Australia’s offshore future” (page 103).

Thomas also will be managing production technology articles as Dick Ghiselinmoves to the E&P Advisory Board, where he will continue offering editorial guid-ance and industry insight gained during 50 years in the oil and gas industry.

The directive, “Change before you have to,” is attributed to Jack Welch, chairmanand CEO of General Electric between 1981 and 2001. ForWelch, change often came at the price of losing people.Fortunately for E&P, change for the better has come fromadding people who bring with them assets in the form ofbreadth, depth, and industry experience.

As ISEE IT

EPmag.com | April 2011

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Change before you have to

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Read more commentary atEPmag.com

JUDY MURRAY Editor [email protected]

Editor JUDY [email protected]

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Executive Editor Online RICHARD MASON

[email protected]

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[email protected]

Group Publisher RUSSELL [email protected]

Vice President, Digital Media RONS DIXON

Senior Vice President, Consulting Group E. KRISTINE KLAVERS

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Executive Vice President FREDERICK L. POTTER

President and Chief Executive OfficerRICHARD A. EICHLER

05 AsISeeIt_Layout 1 3/24/11 9:13 AM Page 5

HART E ERG

N iehls Bohr’s words resonate as the world looks to itsenergy future. With the Earth’s population at seven

billion, oil prices stressed by turmoil in North Africa and the Middle East, global warming concerns, the riseof China and India, and the shadow cast by the tragicevents surrounding the Deepwater Horizon, the industry is hearing a call to action that is unambiguous.

From uncertainty to opportunityAgainst this backdrop of uncertaintyand the inevitable anxiety of theunknown, there is a parallel world fullof promise heralded by the emergenceof a highly competitive, diversified, andtech-savvy energy market both in theUS and around the globe.

Currently, the US imports roughly20% of its total energy needs – esti-mated at around 45 MMboe/d. Theimpact is significant and burdens theUS balance of payments. What is lesswidely recognized, however, is the over-all inefficiency of energy use. Approxi-mately 61% of energy produced in theUS is lost. On average, only one out ofthree reservoir barrels is recovered,which translates to an overall efficiencyof only 13% for oil that is converted toa useable form.

Looking ahead, energy efficiency –both generation as well as consumption– offers a wide-open landscape for busi-ness opportunities, especially to those enterprises thatcan deliver superior efficiencies in capital deployment.The industry is ripe for a fresh look at energy efficiency.

Technology reshaping future of oil Technology is reshaping every facet of people’s lives –from Twitter to iPhones to cars that self-park. Theenergy world is similarly affected by a wave of changepowered by new technologies. The resurgence of US liquids production in recent years (5.5 MMgal/d

and trending up) led by Gulf of Mexico developments as well as the steady growth of unconventional gas pro-duction’s six-fold increase over the last two decades toapproximately 32 Bcf/d in 2010 are clearly attributableto advances in technology. To some degree, the returnalso is due to more robust, albeit volatile, prices.

The energy industry can expect continual advances in diagnostic and production-oriented technologies allowing greater command and control of wells tens ofthousands of feet underground. Saudi Aramco’s new-generation fields such as Shaybah, Haradh, and Khurais

bear the latest testimony of multifold and sustainableimprovements in well productivities as a direct conse-quence of new technologies.

The planet is endowed with plentiful sources of gasand oil, conventional as well as unconventional. Someestimates place global unconventional gas resources atabout 33,000 Tcf (roughly 5.5 Tboe). The outlook forliquids is no less promising. At current rates of globalconsumption, there are sufficient supplies to last intothe 22nd century.

April 2011 | EPmag.com6

industryPULSE

New dynamics ahead for energy, oil ‘It is difficult to make predictions, particularly about the future’ – Niehls Bohr, 20th century Danish physicist.

On average, only one out of three reservoir barrels in the US is recovered. (Source:

National Petroleum Council)

Nansen G. Saleri, Quantum Reservoir Impact LLC

06-9 IndPULSE-APR_06-9 IndPULSE-APR 3/23/11 4:55 PM Page 6


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The interesting, and arguably notobvious, consequence of these tech-nology advances is that they generateefficiencies on both the supply andconsumption sides of the energyequation. Thus, while the globaldemand for energy will continue to grow, the makeup of the globalenergy pie has yet to be determined.Oil will be a key player, but its sharewill depend on how well it doesagainst its competition – fossil, non-fossil, or renewables – on threebenchmarks: 1) financial, 2) environ-mental and safety, and 3) public perception.

While the Deepwater Horizonaccident was a tragedy, it also was acritical milestone, irreversibly changing the entire risk assessment framework of the industry on all three benchmarks.

Minimizing carbon footprint and resource steward-ship (a Bill of Rights) likely will become the new impera-tives for the energy industry. Slashing the current costsof carbon sequestration by an order of magnitude, forinstance, offers a worthwhile grand challenge to theR&D and technology communities in oil and gas.

Transitioning from peak supply to peak demandThe world already has entered a new energy era that isdramatically more competitive, diverse, and high-techthan the past. Oil and gas, conventional and unconven-tional, have to compete head-to-head with a host of fossil-and non-fossil-based competitors, namely coal, nuclear,and renewable alternatives such as solar and wind.

Oil’s role as the preeminent form ofenergy will be challenged by economic, envi-ronmental, and public perception metricsthat are ever-changing. The world has movedinto the peak demand mode away from thepast paradigms of peak supply. Global con-sumers are the kings and will continuallyreposition the market.

This new age offers huge opportunities fornew companies that can deliver superiorreturns on capital deployment across allaspects of the energy business – exploration,extraction, and consumption. The age of13% usable energy efficiency as the norm isover. The future energy picture for the US orthe planet is not constrained by the availabil-ity of supply – either for fossil or non-fossilfuels – but rather by the efficiencies of gener-ation and consumption.

Editor’s note: This article is based on a speechgiven by the author at the Association of CorporateGrowth luncheon on Jan. 11, 2011 (available atwww.qrigroup.com).

industryPULSE

At current rates of global consumption, there are sufficient liquid hydrocarbon

supplies to last into the 22nd century. (Image courtesy of Quantum Reservoir

Impact LLC)

Some estimates place global unconventional gas resources at about 33,000 Tcf.

(Source: Journal of Petroleum Technology, December 2010, www.spe.com/jpt)



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Canada invests in technologies to improve oil sands developmentCanadian government agencies are assisting companies in developing technologies that will increase production, decrease water use, and lead to faster reclamation in Alberta’s oil sands.


worldVIEW

I t is common knowledge thatthe green movement has tar-

geted the oil sands. What is some-what less well publicized is thefact that the Canadian govern-ment has targeted the oil sands aswell – as an area for technologyinvestment that will improve theenvironmental footprint of devel-opment operations and increasethe amount of oil produced.

According to Chris Holly, whoheads the Research and Technol-ogy branch of the Alberta Depart-

ment of Energy, there have been approximately 50industry projects funded over the past five years. Hollytalked to Hart Energy about some of the research effortsbeing funded by the Canadian government and thepotential gains those efforts represent for the industry.

What has Alberta done to match production to changingdemand?Canada has no national oil company, so essentially theprocess that is used is that we regulate in a market envi-ronment. We regulate environmentally in a market envi-ronment, and we also regulate, I would say, in terms ofresource development by our use of fiscal policies, royal-ties, and taxes.

When oil spiked in 2007/2008, we saw a lot of reinvest-ment. That’s just normal corporate behavior. You have alot of cash flow, you don’t want to pay taxes, you reinvest.This created a period of capital inflation. After a while,companies found they couldn’t afford the capital infla-tion, and they backed off.

The profits also got involved very actively with develop-ing better labor policies in terms of labor training andrelaxing immigration policies so we can bring in a lot ofpeople, for example, from Venezuela.

The government certainly did all sorts of things toaddress some of the social infrastructure concerns, butthe reality is the industry ended up taking a look at priceand said, “I can’t afford to build in this capital and thiscost environment.”

Oil prices are on the rise again. Has the fluctuation in oil priceaffected investment in technology in your group in the last cou-ple of years?The nature of our heavy oil and oil sands is such that ifyou’re putting in the capital expenditure, you’re notresponding to short-term business cycles. You’re respond-ing to long-term expectations. So actually, in the last fewyears, we have continued to see the sort of same produc-tion growth rates that we’ve been seeing here in the last10 years. Now we’re producing, if I recall, out of what’sdeemed the oil sands deposits of about 1.5 or 1.6MMbbl/d, and we’re producing about 500,000 or600,000 b/d of conventional oil.

I should point out that there really isn’t any distinctionbetween oil and oil sands. We have heavy oil deposits. Weare producing oil sands through primary technology. Wecan pump it cold.

And we’re using polymers in the process. It’s beenstated that Alberta may be one of the leading jurisdictionsin the world in the use and invention of polymers forheavy oil production.

We’re seeing some very interesting successes. We’veseen projects go from 1,000 b/d as pilots to 50,000 b/dcommercial.

There are four polymer projects that have been pub-licly announced. We fund some of these technologies interms of what we would call “First Pilots,” so a lot of theinvestment actually is industry money. We potentiallycome in somewhere in the order of 30%, somewhere inthat range.

What initiated polymer development?It had much more to do with industry expressing interest.Some of the earlier projects have a Chinese connection.The Chinese have been quite heavily involved in the use

Christopher Holly

(Image courtesy

of the Government

of Canada)

Tayvis Dunnahoe, Senior Editor

10-11 WorldView-Holly_10-11 WorldView-Holly 3/23/11 4:55 PM Page 10

of oilfield chemicals in their heavy oil production. If youfollow at all the World Heavy Oil Congress, you’ll recog-nize that Canada, China, Venezuela, and others are mem-bers of it. So we actually saw a technology interest possiblycoming from that aspect into Alberta.

Polymers have been around for years, but now a newgeneration of polymers is being looked at. We’re seeing alot of use of polymers in tailing management in oil sandsmines, being able to take the water out and de-water thetailing streams. So, a very fascinating area of technology isdeveloping with some very interesting commercial results.

We’re doing some in-house work right now to get a bet-ter understanding of what has happened in the dynamicsof the polymer markets.

What are some of the environmental advances in oil sandsdevelopment?On the mining side, there has been continuous improve-ment in operations to reduce the amount of energy thatis used in the extraction process. We’ve reduced the tem-perature from hot water to a warm-water extractionprocess, and that has had a huge impact on reducingenergy costs.

Because the oil sands are water wet, you can extract theoil from the sand with the use of caustics, soaps, and hotwater/warm water. Improvements in technology, bothfrom a mechanical process and from an oilfield chemicalprocess, have sped up the oil separation process using lessheat and less water. Less water means a lower pumpingrequirement, so you have an environmental benefit.

What we’re also seeing on the tailing side now is muchfaster opportunities to perform reclamation and to de-water the tailing streams. And as you do that, you havethe opportunity of bringing back the land and more pro-ductive capability quicker.

On the in situ side, you’re seeing an advancement oftechnologies for the use of polymers for heavy oil produc-tion. On the thermal in situ side, we’re seeing some realimprovements in terms of understanding how the holechambers – the steam chambers – are developed and howoil can be produced. So now you hear about things like“Fast SAGD” (fast steam-assisted gravity drainage) whereafter the chamber has been heated, we actually have theability to put it in horizontal wells without a steamer toproduce the oil because the chamber is hot.

We’re looking at solvent addition that is facilitating theability to keep a well in productive capability. One of therecent milestones is the advancement of metering andmonitoring technology. We’re getting better and better atcontrolling what we’re doing, but you have to see what ishappening downhole. So whether you do that using new

seismic technologies, new drilling technologies, or newmonitoring and metering technologies, it’s a critical com-ponent of the process.

What are some of the steps being taken to execute faster reclamation?The fact is that 80% of reclamation involves replacementof material back in the hole, and it is the final 20% thathas to do with the topping, the putting on of the organicmaterial – the topsoil and the vegetation. Part of the min-ing process, as in coal mining, is filling in behind theoperations. We do have to have some tailings pondsbecause of the extraction process, but that does not rep-resent the majority of the area. The majority of the areacan actually be refilled.

The other thing that people have forgotten is that whatis being reclaimed today (and very close to having finalcertificate) are areas that were disturbed 20 years agowhen mining levels were in the range of 65,000 to 70,000b/d. Today, we’re probably producing 800,000 b/d ofmining, but people are looking at it and saying, “Well,why haven’t you reclaimed at the same rate?”

There is a lot of government policy directed towardspeeding up the reclamation cycle. We’re funding differ-ent technologies to improve upon the reclamation andseparation of materials. And we’re looking at some inter-esting success that’s coming forward.

EPmag.com | April 2011 11

Canada currently

produces 1.5 to

1.6 MMbbl/d from its

oil sands deposits.

10-11 WorldView-Holly_10-11 WorldView-Holly 3/23/11 4:55 PM Page 11

John Hofmeister weighs in on North America’s energy supplyRestricted production in the Gulf of Mexico will push America to increase oil imports.


worldVIEW

A fter his 2008 retirement from the position of president at Shell Oil Co., John Hofmeister

founded and has served as chief executive of Citizens forAffordable Energy. The organization’s goal is to educateAmericans about energy and environmental challengesand solutions. Hofmeister spoke with E&P magazineabout some of those challenges as well as crude supplyinitiatives aimed at fueling North America’s energyindustry and consumer economy.

What is your outlook for energy affordability?It’s my view that global demand, including US demand,is going to push oil price to triple digits this year, proba-bly in the first half.

Is it accurate to expect US $5/gal gasoline in 2012 and$100/bbl crude in 2011? I think OPEC will be reluctantto increase production for a variety of reasons, not theleast of which is that some of its members are reallystrapped with declining production. They need all themoney they can get.

How important is the resumption of deepwater drilling to USenergy markets?With the Department of the Interior managing the rich-est oil basin in the US to full stop in terms of futuredrilling, production only declines in the Gulf of Mexico.

The absence of drilling will lead to production declineat a time when the world needs more oil, not less. I amprojecting unscientifically up to 1 MMbbl/d short by theend of 2012.

The natural decline of production with the absence ofnew drilling yields roughly 1 MMboe/d out of the Gulfof Mexico by the end of 2012 into 2013. It will take yearsto recover that.

Will an incline in onshore unconventional oil production off-set the decline in offshore production? The Department of the Interior will quote figures of(onshore) drilling increases for 2010 versus 2009 tomake it sound like drilling is increasing, not decreasing.

But that’s different from (declining) production num-bers from the huge reservoirs of the Gulf. Those will notbe offset by the small incremental amounts of uncon-ventional oil coming out of the shale plays.

In other words, you can drill night and day, which theydo, but the amount of production is so modest relativeto the big reservoirs in the Gulf. You are not discoveringnor producing at the enormous quantities of the Gulf ofMexico reservoirs.

If you compare Macondo at 65,000 b/d spewing intothe Gulf versus 1,000 b/d initial production, there is nocomparison.

We have in the Piceance Basin in the Rockies – inWyoming, Utah, and Colorado – about 1 Tbbl. Butdevelopment has been blocked, particularly by Denverelected officials, most notably then Sen. Ken Salazar,who now happens to be secretary of the US Departmentof the Interior.

John Hofmeister is founder and CEO of Citizens for Affordable

Energy. (Image courtesy of Citizens for Affordable Energy)

Greg Haas, Editor, Hart Energy’s Refinery Tracker

12-15 WorldView-Hofmiester_12-15 WorldView-Hofmiester 3/23/11 4:55 PM Page 12


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When you have the Depart-ment of the Interior run by anattorney general – which he wasbefore he was senator – and aprosecutor from the Departmentof Justice, Michael Bromwich(now director of the Bureau ofOcean Energy Management, Reg-ulation, and Enforcement), youget what you get.

That’s largely a mindset whichsays, “Stop!” so that no risk istaken, or “Stop! Or we’ll prose-cute!” So we have been in a stoppage.

Juan-José Suárez-Coppel, CEO of Pemex, disclosed plans onCNBC to ramp crude production for internal consumptionand export. Will rising Mexican production alleviate the USshortfall from offshore?The predicted rate out of Mexico that we heard was torecover production to 3 MMbbl/d by 2015. But that didnot sound unequivocal – he did not sound sure – and itwas not a hard number.

If you tell the whole story of Mexico, they have mort-gaged oil production in prior years for future produc-tion. They are mortgaged nine years into the future.

They were paid already for production for 2013, 2014,2015, etc. So what they have to do is to keep mortgagingfuture production.

And that (forward arrangement) was mortgaged atthen-current crude oil prices. Mexico faces a severe rev-enue problem which causes them to mortgage evenmore production. So the people who are buying thosefuture contracts, they’re buying a lot of air.

The CNBC reporter after the (Pemex) report notedthat when politicians run the industry, you get what youget. The same principal applies in this country when thepoliticians run the industry.

Right now what we are seeing is the Department ofthe Interior running the Gulf of Mexico right into theground.

Canada already is the largest source of imported crude oil tothe US. The TransCanada Keystone XL pipeline expansionseeks to extend that supply. Do you have any thoughts on theadministration’s delaying necessary permissions? It is an absolutely necessary part of our future infrastruc-ture if we are going to continue to supply American con-sumers with the fuels that they need to live their lives andto keep our economy strong. That’s point number one.

Point number two is that theecological issues raised by eitheroil sands or by pipelines of suchgreat length crossing rivers, val-leys, and lakes are fundamentallymanageable.

If the American consumer isnot going to be able to access theCanadian oil sands product, youcan be absolutely 100% sure thatChinese consumers will.

Canada’s other major oil pipelineoperator, Enbridge, recentlyannounced an investment by China’s

Sinopec to study the feasibility of a westward pipeline fromAlberta to Canadian West Coast export facilities. Do you haveany insight on that?The reality is the oil sands oil is going to be produced,period. It can go south, or it will go west to China. It willbe consumed.

If the administration is so short-sighted and so insensi-tive to the affordability of fuels by the citizens of the USas to deny the pipeline’s construction, it is only a matterof time before the populace changes who is in govern-ment through an election cycle.

The president is at risk of losing a re-election contestbased upon the real pocketbook issue of gasoline prices.His own Department of the Interior is directly contribut-ing to the risk – by refusing to produce oil.

What else is in the hopper for the US E&P industry?Two other (indicators) show the Department of the Inte-rior is intent on stopping things from happening ratherthan making things happen.

The Interior secretary, of his own authority and with-out any congressional interactivity, has created a newconcept called the “Wilderness Zone.” The secretaryhimself can determine areas sufficiently sensitive to dis-allow mining, drilling, or any other industrial use. Evenworse, in my opinion, (is the development that) early inDecember, the secretary announced that he would post-pone the next five-year plan, due in 2012, to 2017.

That is a message to the industry that, whether thepresident gets re-elected in 2012 or not, the Departmentof the Interior of the United States of America is puttingon any offshore leases for the duration of how long theymight be in office.

That says to the world that the US is not going to pro-duce its own oil and is going to rely on more imports.This creates the psychology of high-priced crude.


The president is at risk of losing

a re-election contestbased upon the real pocketbook

issue of gasoline prices.

worldVIEW


Acommon problem in the oil and gas industry is amature asset that needs more attention than the

asset team is capable of providing. In one recent case, the team leader was managing a

mature asset that needed a thorough engineering study(the last one had been done eight years prior), but hedid not have the staff to execute the project inhouse andwas unhappy with the current batch of available consult-ing options. He considered them either too expensive atUS $1,200 to $3,000 per man day, unavailable (“I canstart in six weeks”), or inflexible in their work methods(“I only know one software package”).

The challengeThe team leader needed to have anexisting Petrel model updated dueto the acquisition of an adjacentfield. He needed to have this modelhistory-matched and upscaled andsimulated in Eclipse. Ultimately, heneeded to know where to drill the nextthree infill wells.

To solve this problem, he tried a risingclass of consulting engineering companiesthat are classified as “iEngineers.” iEngineersexecute classical subsurface interpretive and engi-neering work over the Internet using the customer’snative software and data platforms. This concept is thelogical extension of the “telecommuting” practiced byalmost all E&P engineers today, where people are work-ing on desktops in one location with big servers anddata systems in another location.

iEngineering is not outsourcingiEngineering companies differ significantly from out-sourcing in that all work is executed on the customer’ssoftware platforms using remote access tools such as Cit-rix or ThinAnywhere. Outsourcing can be thought of as“sending work overseas,” iEngineering should be thoughtof as “flying in day workers over the web.” Using the cus-tomer’s software platforms ensures work consistency,

work processes and methodology control, informationsecurity increases, and ultimately lower cost per projectversus traditional consulting service providers.

In a typical iEngineering engagement, the customerand consultant must agree on three critical issues: com-munication, access, and expectations.

In the example, the team leader and consultant agreedon all three. Regarding communication, the consultingteam leader (a reservoir engineer with 15 years of model-ing experience) flew to the customer’s office for the firsttwo weeks of the three-month project to ensure a smoothkickoff. There also were scheduled biweekly projectreview telemeetings using Webex, in which the consultingteam presented a milestones progress Gantt chart, tech-

nical issues update, and project processissues. Outside of the weekly meetings, theasset team leader and iEngineering teamleader remained in frequent email and tele-phone contact.

The IT group helped establish secureremote logins to the necessary Petrel and

Eclipse licenses. The licenses and project datawere placed in a secure “demilitarized zone”that was established separately from the E&Pcompany’s core network. All consultants

working on the project were required to pro-vide photo identification information and for-

mally register as users with the IT department.To manage expectations, the oil company and team

lead agreed to a “walk before you run” work arrangement.For the first few weeks, the iEngineering team reviewedevery decision point. Once a level of trust and comfort wasestablished, the team was able to scale back the level ofapproval to what was termed, “Ask if you get lost.”

As the weeks progressed, the relationship becamerelaxed. A change in direction encountered during thesecond month required an extension of the project scopeand budget. When the project ended, the remote teamprepared its technical conclusions and a draft of the finalreport for review. The asset team leader led a manage-ment presentation teleconference during which theiEngineering team lead presented a 15-minute overviewof the technical recommendations for the field.

Management was interested in this alternative work

New model exists for engineering consultingiEngineering has the potential to accelerate subsurface studies.

Richard Ward, Tiandi Energy


managementREPORT

16-17 MgtReport_16-17 MgtReport 3/23/11 4:55 PM Page 16


iEngineers execute classical subsurface interpretive and engineering work over the

Internet using the customer’s native software and data platforms.

arrangement and asked the asset team leader about the “real-world chal-lenges” of the project. He outlined the initial start-up problems concerningdata availability and agreement on reporting requirements.

A new alternative The key takeaway is that for mature assets in need of re-engineering work,an alternative source of consulting talent now is available. Accessing andusing this talent leverages existing software and hardware investments madeby all E&P companies, but it does require an adjustment to a modified workarrangement.

In practice, this alternative consulting arrangement has resulted in:• Faster start times – Due to increased availability of employee consulting

engineers in these new companies, customers are able to begin projectswithout delay;

• Greater consistency – By definition, iEngineering projects use the cus-tomer’s existing software and data platforms to execute the interpretiveand engineering work. This greatly increases the transparency and con-sistency of the consultants’ work with the processes and norms of thecustomer. It also reduces the “black box” situation in which a projectreport is delivered, but the customer does not know how the results wereobtained; and

• Lower cost – iEngineering companies are global by nature. Their cus-tomers, staff, and employees are located worldwide. This built-in accessto the global talent marketplace has resulted in a significant reductionin skill-equivalent day rates. In several known cases, total project costswere 40% to 60% less than the traditional alternative, while quality anddelivery times were maintained.

A transformative opportunityTo date, iEngineering companies have mostly executed traditionally definedprojects, including seismic interpretation, geomodeling, simulation, declineanalysis, and well data entry using traditionally sized consulting teams ofthree to seven people. However, the potential exists for transformativechange within the industry. Resource constraints and high day rates havelimited the scope of projects that could be conceived and executed.

With access to fundamentally unlimited resources, the scope and scale ofwhat is possible could change within the industry. Now, when an asset teammanager arrives at the office on a Monday, there could be 20 trained petro-physicists waiting and ready to tackle “a big problem.”

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In some ways the oil and gas industry always has beenahead of the curve when it comes to compute power –

geophysicists, for instance, developed algorithms yearsago that are just now being used because computersfinally have caught up.

In other ways, however, the industry seems hopelesslymired in some time warp while other industries aremuch more nimble in adopting new technology. Takedata management, for instance. Data management“solutions” have been around as long as computers have,yet many companies still struggle to get a handle onwhere their data are and how best to access them. Addto that the fact that a data management system thatworked well five years ago now is obsolete, and a fairlysevere problem begins to rear its ugly head.

OpenText is helping other companies catch up to thelatest developments in computing, including social net-working and computing in the cloud. Tom Jenkins,executive chairman and chief strategy officer for Open-Text, discussed the challenges facing the industry today.

The generation gapWhen Jenkins recently was in Houston to meet withenergy companies and showcase his products, the CIOsof these companies discussed some of the issues theyfaced with the younger people in their organizations, a group that Jenkins refers to as “digital natives.”

“Our reality is that Facebook is now used more thanGoogle,” he said. “Google was the old way of us going tothe computer to get information. With Facebook, we goto another human being to get the information.”

In the author’s note to his new book, Managing Con-tent in the Cloud, Jenkins writes about the explosion ofsocial networking and why it has been so successful.“These applications became so widely used because theyallowed people to find information, collaborate, andcommunicate faster than they could using other servicesor similar portal sites. The rise of the Internet as a con-nected network has allowed human beings to connectand generate ‘virtual’ human intelligence on a massscale.”

With a growing workforce that relies on Facebook formuch of its information, it seems somewhat ironic thatall of the companies represented at the meeting blockits use by their employees. But when informationresides outside the firewall, problems can occur.

In one example, an airline discovered that its propri-etary information was showing up on YouTube. Typicallywhen a part is changed, the airline needs approval fromthe Federal Aviation Agency or other governing bodiesand then has to translate that information into dozensof languages to be included in manuals all over theworld. Employees instead had videotaped the actualchanging out of the part.

“It’s language-invariant,” Jenkins said. “It’s monkeysee, monkey do. The problem is that the corporationdidn’t have an internal method for distributing theinformation, so the proprietary information was starting

digitalOIL FIELD

The industry needs next-generationcontent managementIn a world that has been rocked by new computing techniques, the oil and gas industry cannot afford to be left behind.

Rhonda Duey, Senior Editor

A website created for the G20 summit allowed participants to

communicate through a website that felt like social networking

but was completely secure. (Images courtesy of OpenText)

18

18-23 DOF-opentext_Layout 1 3/24/11 9:51 AM Page 18

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to pop up outside the firewall. It’s because people were getting frustrated.”That frustration is driving the need for companies to create their own

internal social networking. OpenText’s solution is to create internal ver-sions of Facebook, YouTube, Wikipedia, etc., so younger workers can obtaininformation in ways that are comfortable to them without breaching com-pany security in the process.

“Why would corporations not do this?” he asked. “The corporation thatdoes versus the one that doesn’t is going to be way ahead.”

Embracing the cloudThe profusion of digital devices – cell phones, BlackBerrys, iPhones, iPads,etc. – has had a profound effect on the way business gets done, Jenkins said. “In the old world, we were PC- and data-driven,” he said. “Now we’remobile, and we have remote control of the desktop and remote servers.The cloud has really expanded the flexibility of what we can do.”

Jenkins showed an example of a “command and control” center in amajor US city. Information from a multitude of sources – national news,weather maps, traffic updates, etc. – was constantly being updated on a single screen, what Jenkins called a “video mashup.”

“It allows you to take all of these inputs of information, both internal andexternal, and get a view of what’s going on,” he said. “That’s something thatfor the oil patch is absolutely essential. It doesn’t exist today. But it should.”

With incidents like the Macondo disaster fresh in the industry’s mind, it is clear that this type of integrated, streaming data system potentially couldavert future catastrophes. “The sooner you can react effectively, the less itcosts,” he said.

In fact, much of what Jenkins preaches is the need for accountability. Hesaid this type of solution is particularly useful in industries that are informa-tion-intensive and heavily regulated. He showed an example of a page thathad been created for the G20 meeting in South Korea. The website wasmuch like a Facebook page, but it was totally secure. Users could form com-munities, post blogs, play videos, and chat. But the website also offered fullrecords management and archiving and would, Jenkins said, meet the testof any government regulatory body. And it was accessible and instantlychangeable from a variety of digital devices.

That mobility is something the oil industry can take advantage of. “Theamazingly transformative thing is your ability to manage information, shareit, and act on it,” he said. “We’ve never had anything like this before. This isso beyond a cell phone now.”

Productivity gainsAll of these new ideas are intended to improve productivity. Decisions canbe made more quickly, and records of these decisions are captured to main-tain the audit trail. “This stuff gives people a fighting chance to be both dig-itally interactive and protected,” he said.

Currently the oil and gas industry is in the process of finding, storing,and integrating its data. The next step in the process will be what Jenkinscalls “semantic navigation.” This is a form of artificial intelligence or neuralnetworking where heuristic algorithms “teach” the system to recognize pat-terns and aggregate content appropriately. This is taking place today on


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some websites. Jenkins gave an example of a newspaperwebsite on which the main story would change basedon the reader’s history. “They’re serving up informa-tion they know is more relevant to you,” he said. “Theywant you to stay on their site longer.”

No companies in oil and gas are using this concept in an organization-wide sense, although certain seismicprocessing techniques do employ the neural networkconcept. Jenkins sees the semantic navigation as being“the next natural step.”

Ultimately, semantic navigation will enable corpora-tions to learn from past mistakes and achieve greaterproductivity gains. It also will serve as a “corporatememory.”

“The digital natives think differently than we do,”Jenkins said. “A lot of the discussion was about how to build social networks, private-label Facebooks andYouTubes and Wikis, so that the younger users can start to learn from the previous generation without tax-ing them.

“It’s a huge dilemma for the industry because, on theone hand, the lessons of the past keep that corporationout of trouble, but if they don’t embrace the new tech-niques and technologies, they will fall behind in pro-ductivity. You have to build an effective compromisebetween the two worlds. It’s like a football team – youneed rookies, and you need the veterans. The coachhas to coach for both. If you don’t have that combina-tion, you’re going to lose.”

digitalOIL FIELD

Semantic content is analyzed, annotated, and related.


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The move toward automation on offshore facilities hasallowed drilling and production systems to work more

efficiently. Today, standard operations can be carried outmuch more quickly than ever before, and sensor systemsdeliver increasingly more real-time data. Intelligent opera-tions (IO) puts information in the hands of decision-mak-ers in real time, expediting the speed with which decisionscan be made and, in the end, increasing drilling and pro-duction operations. In short, IO has delivered efficienciesthat were only dreamed about decades ago.

Along with efficiencies, however, software systems alsopresent challenges.

For software suppliers and system integrators – typicallybuilders and shipyards – the large number of systems pres-ent on today’s offshore facilities poses an enormous chal-lenge. While hardware components are designed anddeveloped with the idea in mind that they have to fittogether at some point to form a system, software followsno such protocol, which means when the time comes forthe individual software programs to communicate, the

path for communication normally is anything but smooth.Making communication possible takes a great deal of

time. Unfortunately, time is money, and the longer opera-tions are delayed, the more costly the integration processbecomes.

Paving the wayAccording to Charles McHardy, director of operations forNorth America in the Gulf of Mexico region for DNV, themore critical software becomes, the greater the challengeof integration.

“If you look at the digital oil field, the trend continuesto be toward more dependence on information technol-ogy and software,” he said. This has become a concernbecause while the industry becomes more dependent onthese systems, the systems themselves are becoming morecomplex and more critical to operations.

That observation was the impetus behind DNV’s initia-tive to create an Integrated Software Dependent Systems(ISDS) notation that provides a common framework forcarrying out software integration. Quite simply, the ISDSnotation focuses on how to set up and run a project inwhich software integration is critical and how to developquality assurance processes that will last throughout thelifetime of the vessel on which the systems are installed.

David Card, technical director for software and systemsreliability at DNV, explained that a lot of the problemsthat arise during commissioning center around gettingthe systems to communicate with one other. “If you estab-lish up front an interface specification and require ven-dors conform to it, you can avoid a lot of those problems,”he said.

Applying the class notation helps owners and operatorsfind a balance between the opportunities and the cost ofautomation and to manage the risk related to poor quality,incorrect functionality, and unsafe behavior. The ISDSdoes not impose a new quality system, Card explained. Itensures integration activities are planned, executed, andmanaged according to best practices.

By streamlining the integration process, this guidanceimproves project economics by reducing the time neededto integrate systems and commission an offshore facility,minimizing downtime and expediting initial production.

digitalOIL FIELD

New standard streamlines software integrationISDS provides guidelines for tackling costly software integration challenges that slow down commissioning.

Judy Murray, Editor

This chart shows a typical distribution of activities throughout the

phases of software development and commissioning. (Images

courtesy of DNV)

24-26 DOF-dnv_24-26 DOF-dnv 3/23/11 4:56 PM Page 24

digitalOIL FIELD


Short-circuiting miscommunicationThe ISDS identifies certain practices or processes that mustbe in place. “The ISDS doesn’t tell you how to design orintegrate a system,” Card explained, “but it tells you, forexample, that you must have an interface definition, thatthere has to be a place where you write down what all of theinterfaces are, and that you manage these things so every-body can see the guidelines and everybody can conform.”

An integration plan is required. Although this seems as ifit should go without saying, Card said, what has happenedin the past is that testing often has not been carried out ina prescribed order, and that has led to problems.

Sometimes during commissioning, systems are beingtested by different vendors at the same time, and the testsare not compatible. For instance, Card said, tests for theemergency shut-down system and the drilling system havebeen conducted at the same time. Though it is obviousthat these tests cannot be carried out simultaneously, thefact is that if testing is not planned, it is easy for conflictingtests to overlap.

“Someone has to think about the order in which soft-ware integration testing should be done instead of allow-ing everybody to show up in the yard and carry out thesetests in any order,” Card said. Software often arrives late –after the hardware has been delivered and installed – sothe order of testing may not be the same as the order ofinstallation.

Preparing for changeBy and large, drilling contractors have given the ISDS nota-tion a warm reception. “We came out with the class nota-

tion toward the end of last year,” McHardysaid. “It’s been very, very well received, somuch so that we have at least a couple of themajor drilling contractors saying all new-builds going forward will have this notationfor all of the complex control systems.”

The reason for this, McHardy said, is thatrig owners are used to a class regime whereclass notations ensure that what is deliveredfrom the yard meets their needs and has the

functionality and reliability required. This eliminates issuesin the operational phase.

“The rig owners we talked to saw the ISDS class notation– or the potential for such notation – as fulfilling a similarrole for them,” McHardy said. “They were particularly keento see not just the recommended practice but somethingpractical, a class notation they could use.”

With drilling contractors embracing the ISDS, there is a need for training, and that training has to be accom-plished soon so yards are able to comply with the demandsof their customers. “We’ve been working on the yards aswell as with workshops toward the main yards in Korea likeHHI, DSME, and Samsung,” McHardy said. The goal is tohave the yards ready and able to work to contractors’requirements.

According to Card, Petrobras was one of the earlymovers, asking DNV to conduct an ISDS notation work-shop for company personnel and the company’s suppliersof automated systems. “One of the feedback items that wegot from that workshop was that they really liked the ideathat the roles were defined because it clarifies the expecta-tion of who is supposed to do what,” Card said. “The sup-pliers are supposed to do certain things, the integrator issupposed to do certain things, and the owner is supposedto do certain things. With the roles clearly defined, youdon’t get into the situation of finger pointing and, ‘Whydidn’t you do that? I thought you were going to do that.’”

One of the most powerful things about the notation,McHardy said, is that in identifying roles and responsibili-ties, it will help eliminate unnecessary downtime. The ISDSnotation lets software suppliers know the requirementsearly enough in their design and development process andin their testing and verification of the software so problemscan be avoided in the hookup and commissioning phase.

“It’s not just a case of running into issues when the riggoes out to drill and suddenly things are not doing whatthey should be doing,” McHardy said. “It’s actually in thecommissioning as well. It doesn’t matter if you’re delayed20 days during commissioning or 20 days on your first well.It’s still 20 days at a cost of US $600,000 a day in lost timeand production.”

An “independent verifier” is an organization mandated to inde-

pendently verify that the system is developed according to the

expected rules, standards, processes, and quality.



At a time when reservoirs are becoming harder to find, PGS delivers theindustry-leading solutions you need.

PGS can help your business achieve greater efficiencies and competitiveadvantage with our full range of ground-breaking technolog ies - one ofthese is our world-class seismic fleet, which has the ability to tow up to22 streamers per vessel .

We set the standard for industry service, with our unique people-orientedapproach. During every project, you can count on our advice and support,because we are committed to helping you reach your business goals.

At PGS, we are your partner in technology, quality and reliability.

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While some majors have maintained active R&Ddepartments, others have opted for a more dis-

tributive model, funding research through service com-panies and universities. While this often is a good wayto pursue targeted research, it makes it more difficult toaddress “grand challenges.”

The Research Committee of the Society of Explo-ration Geophysicists (SEG) decided to buck thistrend. In 2004 and 2005, members envisioned a col-laborative research effort with a targeted industrialgoal. The result was the SEG Advanced ModelingCorp. (SEAM), established in 2007.

SEAM’s goal is to identify a grand challenge withinthe area of geophysical modeling, conduct researchphases, and offer earth models and simulated data representing significant geophysical challenges.

Phase I, which began in March 2007, focused ondeepwater subsalt tertiary basins. Expected to be com-pleted in 2010, it was extended by an alliance with theResearch Partnership to Secure Energy for America,which provided an additional US $2.6 million.

Recently SEAM announced plans for Phase II, whichwill focus on land seismic challenges. Several oil andservice companies already have signed on to discuss the definition of the challenge and the project scope.

Phase II will focus on three core challenge themes.The first is high-density and areal-extensive acquisitiongeometries. “Industry’s experience has consistentlybeen that subsurface images improve with every acqui-sition and processing advance that moves toward ‘true 3-D,’” the Phase II announcement document states.“Marine wide-azimuth acquisition is a good case inpoint. However, land channel counts have always beenlimited by what is technically, economically, and opera-tionally feasible.” The goal here is to provide simulateddatasets to evaluate the technical benefits of high-density recording.

The second theme is near-surface complexities. Near-surface heterogeneities wreak havoc on noise suppres-sion and data processing and include topography, sanddunes, dry river beds, steeply dipping layers, outcrop-ping refractors, lateral velocity variations, velocity rever-sals, layered basalts, carbonate karst, and anisotropy.

The hope is to provide realistic near-surface earthmodels based on geological parameters transformed to rock physics parameters. “The efficiency of full elastic simulation codes continues to improve, drivenin part by the activities of SEAM Phase I,” the docu-ment states. “Near-surface simulations can now beacquired for evaluation of acquisition, processing, and imaging schemes.”

Finally there is a focus on fractured reservoirs,increasingly important with the growing interest inunconventional plays. While seismic is recognized as a valuable tool for horizontal wellbore trajectory plan-ning and sweet spot identification, its use is compli-cated by vertical transverse isotropy in both theoverburden and the target interval. Horizontal trans-verse isotropy, on the other hand, provides a means of identifying fracture density and horizontal stresses.Project leaders hope to ascertain the relative benefitsof multicomponent data, bandwidth increases, and theneed (or lack thereof) for seismic to be an essentialcomponent of a fractured reservoir exploration anddevelopment program.

Currently a three-year project plan is proposed,although participants in Phase II can modify thisapproach. The first year will focus on earth modeldesign and fractured reservoir investigations, the sec-ond year on seismic modeling simulations and a frac-tured reservoir version of the base-case simulationmodel. A simulated dataset will be acquired in thethird year.

For more information about SEAM, visitwww.seg.org/SEAM.

Geophysicists take on the next ‘grand challenge’SEAM’s next phase will tackle land seismic issues.


RHONDA DUEYSenior Editor

[email protected]


explorationTECHNOLOGY

27-28 ExpCOL_27-28 ExpCOL 3/23/11 4:56 PM Page 27

27-28 ExpCOL_27-28 ExpCOL 3/23/11 4:56 PM Page 28

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wellCONSTRUCTION

Sand management is a reality in life-of-well plan-ning. Standalone screens commonly are used to

mitigate problems associated with fines migration,which can damage surface equipment and result in a rapid decline of production for an otherwise decent well. Gravel packing can assure a clean annu-lar flow where the well bore has eroded in friablezones, but this requires expensive pumping capacityand sometimes more than several trips to provideample protection from solids intrusion. Expandablescreens have seen several innovations in recent years, but even these have limitations in openholeapplications.

What if a material existed that could provide fullconformance with the sand face in just one trip? Thatquestion may soon be answered. Shape memory poly-mer (SMP) technology is not a new science. Open-cellfoams have been looked at for oil and gas applicationssince 1990. It is only recently, however, that theseindustries have found a common ground on which to interact.

Early this year, Baker Hughes Inc. announced itsGeo Form Sand Management System, which usesSMPs to construct downhole production strings thatmeet the sand face, provide ample porosity, and guardagainst fines migration for possibly 10 years or more.

The concept relies on specialized polymers that aremolded and milled to a desired shape and size. BakerHughes has on offer two current sizes. The 27⁄8-in. by 6-in. screen has a fully compacted OD of 4.6 in. Onceactivated, the screen expands to 7.16 in., which is rec-ommended for 6-in. to 61⁄4-in. openhole completions.The 5½-in. by 8½-in. screen fully compacts to 7.125 in.with an expanded OD of 9.390 in. and is designed for83⁄8-in. to 8¾-in. hole. Both screens are designed tooperate between 105ºF to 195ºF (40.5ºC to 90.5ºC),although the company is researching methods toexpand this to a higher range.

According to Baker Hughes, these new screens areideal for gravel pack replacement, long horizontalwells, slimhole applications, and remedial sand con-trol. In their compacted state, the screens have provento withstand scarring in drill tests of up to 4,000 ft

(1,219 m) of lateral movement at 30 rpm.This “smart” material is activated downhole through

exposure to bottomhole temperatures and specializedcatalysts to unlock the compacted screens once inplace, allowing the SMP to return to its original shape,conforming to the annulus of the well bore and fillingin any irregularities as it expands. An interesting fea-ture to these new screens is the material’s replicationof pore space. Whereas porosity is devised from thespace between the solid particles within a reservoir,the shape memory material provides an inverse of thismatrix with its pore space in closer relation to actualgrain size. Also, it is designed with a 10:1 ratio ofradial to axial permeability to prevent solids migrationto the well bore. Fully expanded screens using mem-ory SMPs provide about 80% porosity; even at fullcompaction the screen maintains 10% porosity.

So what is the bottom line? According to informa-tion provided by Baker Hughes, gravel packs have ahistorical transactional failure rate of 16%, whichtranslates to more than five hours of nonproductivetime (NPT) per tool per well. In its current tests,Baker Hughes Geo Form screens have shown a trans-actional failure rate of less than 4%, with an NPT ofless than one hour per tool per well. Overall, this newtechnology could net operators a 75% reduction inNPT and associated costs (roughly US $100,000 perwell) within this segment of the completions process.

As with any new technologyentering the market, it will beinteresting to see how thesetools perform in the fieldand if they will gain accept-ance over time.

Managing sand from the outsetSMP technology is entering the world of well construction.


TAYVIS DUNNAHOESenior Editor

[email protected]


29-30 WellConstruction_29-30 WellConstruction 3/23/11 4:56 PM Page 29

29-30 WellConstruction_29-30 WellConstruction 3/23/11 4:56 PM Page 30

CLEANERAt Newpark Drilling Fluids , environmentalresponsibility is not just technology jargon.Our R&D efforts revolve around innovatingfor a cleaner tomorrow and help us keepour customers ahead of regulatoryrequirements.

LIOL I IT ON..SMARTER.As the leader in high-performance , waterbased drilling fluids technology, we listen toour customers ' needs. In 2010 we launcheda new kind of water-based drilling fluid. OurEvolutionT"l drilling fluid system was createdin response to customer requests for betterperformance in the Haynesville-and beyond.

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productionOPTIMIZATION

Every day, we see our industry, our livelihood, casti-gated in the press and in the halls of government. It

is time to do something about it. With few exceptions,public opinion regarding the oil and gas industry isbased on ignorance. They do not know any better. Andwhose fault is that? It is ours, whether we want to admitit or not.

Our industry has its enemies, but in large part, theseare zealous but misguided individuals who are ignorantof the role played by the energy industry in shaping theworld economy. Worse still, these people have no ideaof the role a strong energy industry will have in thefuture well-being of themselves and their descendents.

Fortunately, we have the talent and resources to dosomething about this. If you accept that90% of the problem is caused by igno-rance, then it should be obvious that90% of the solution can be gainedthrough enlightenment. Those of us inthe industry – yes, I am talking to you –can work to change public perception.No one else will do it, so if it is going toget done, it is up to us – all of us.

There is a popular saying goingaround these days: “If you love freedom,thank a soldier.” We need a similar saying: “If you lovepeace, health, and prosperity, thank the energy indus-try.” Think about it. Without the efforts of the energyindustry, it is very likely that World War II would havehad a different outcome. Without energy to fuel indus-try, there would have been no guns, tanks, planes, orships. Without energy, there would be few jobs outsideof agriculture, and those still farming would be plowingwith a team of mules. Without energy, there would beno international commerce, no trains, airlines, trucks,and cargo vessels. The free world’s economies are builton abundant and reliable supplies of energy. All we haveto do is start talking about this.

Every one of us has the opportunity to sway publicopinion. When we speak to our children, to our friends,to civic and professional groups, we need to tell theenergy story. Talking among ourselves is preaching tothe choir. We need to get out in the world with our

message: “Energy is the lifeblood of our civilization.Today, we derive energy from oil and gas; tomorrow we could tap another resource, but there is no substi-tute for energy.”

Our professional societies and organizations need totake responsibility for educating thepublic. We have been silent too long.Through education outreach, we canengage a generation of young peopleand shine a light on their knowledgeabout energy. In an age where we cansend people into space and bring themhome safely, it is a travesty that there stillare university graduates who think thatoil exists in huge subterranean pools orrivers. There actually are people who

think, “We do not need oil or gas; if we want heat orlight, all we have to do is flip a switch.” There is a grow-ing fringe of the population that believes drilling andcompletion practices are polluting drinking water withmysterious toxins and carcinogens. Who is going to edu-cate these folks? It had better be us because no one elsewill do it.

I want to get off my soapbox long enough to welcomemy long-time friend and colleague, Mark Thomas, tothese pages. Mark is a true professional and a journalistof the highest reputation. He was present at the birth ofHart Energy’s E&P magazine, and it will be great havinghim back onboard. He brings an international perspec-tive at a time when the global oil and gas industry standson the threshold of greatness, with deep-water E&P and the tantalizing pos-sibility of vast worldwide shale gasresources on the horizon.

The adventure continuesIn my final column, I want to challenge each and every one of you to pay a little back to the industry that put food on your table, a roof over your head, and a sense of accomplishment in your heart.


DICK GHISELIN, P.E.Senior Editor

[email protected]

31EPmag.com | April 2011

If you love peace, health, and prosperity,

thank the energy industry.

31 PRODcol_31 PRODcol 3/23/11 4:56 PM Page 31

32

Funny what a difference a decade makes. In 1999, theseismic industry was cursing the multiclient business

model since it had been used as an excuse to keep boatsbusy when no contract work was available. In 2011, themulticlient model is being praised as one of the segmentsthat helped keep the marine industry afloat during therecession and the fallout from Macondo.

That is one of many observations made by companiesin the marine geophysical industry. E&P asked these com-panies about the recession, Macondo’s impact on theirbusiness, and their plans going forward.

The recessionDuring the recession, some companies fared better thanothers. Companies that operate mostly on a contract basissaid that 2009 actually was a better year than 2010because they were working through their backlog,whereas companies that operate more on a multiclientbasis said 2009 was a very difficult year.

“Together with the fall in oil prices and the generaleconomic downturn in 2008-2009, the profit mar-gins for contract seismic were eroded significantly in2010 compared to 2009,” said Per Arild Reksnes,executive vice president, Marine Contract for PGS.“However, the need for new and better seismic data tofind more oil and gas has made oil companies willing tosteadily invest in multiclient data.”

According to Benoît Ribadeau-Dumas, executive vicepresident, Marine Division, CGGVeritas, the mid-decadetechnology gains such as wide-azimuth (WAZ) seismichelped. “Demand was driven by technology (higher reso-lution surveys) and a general increase in regional activity,”he said. “The seismic services market also improved, withcommercial activity increasing globally in most regions.”

However, he added, pricing remained under pressuredue to a longer period of overcapacity than originallyexpected, mainly based on events in the Gulf of Mexico(GoM).

Unlike previous downturns, when oil companies wereless likely to insist on using the latest technology, demandstill was strong for high-end services. “It was interestingduring the recent downturn to note that our clients didnot stop exploring, nor did they ‘trade down’ from WAZ,4-D, and other high-end approaches,” said EdwardKotochigov, marine marketing manager for West-ernGeco. “These services deliver the incremental value clients are looking for.”

He added that, while overcapacity has been an issue,techniques like WAZ “consume many more vessel monthsper square kilometer than conventional narrow-azimuthexploration. This sucks up a lot of vessel capacity, and asthey grow, the industry will face localized shortfalls laterin 2011 and 2012, despite the addition of new capacity.”

COVER STORY:MARINE SEISMIC

Despite two years of setbacks, the marine geophysical sector is poised for busy times.

MARINE SEISMIC Rhonda Duey, Senior Editor

April 2011 | EPmag.com

32-42 COVERstory_32-42 COVERstory 3/23/11 4:57 PM Page 32

33

BGP Inc. already has plans to launch a 12-streamer vessel. The objective is “to meet higher demand from ourclients,” said Zheng Huasheng, vice president of the com-pany. The vessel will be outfitted with ION Geophysical’sDigiSTREAMER system.

This need for the latest data has played nicely into thehands of TGS, a company that relies almost solely on amulticlient model. CEO Robert Hobbs said once compa-nies are ready to start exploring again, the quickest wayfor them to do so is to license data off the shelf ratherthan embark on an expensive and time-consuming pro-prietary survey. It does require, of course, that the databeing shot on a multiclient basis are in an area of interest

to the oil companies. Hobbs said his com-pany has to “stay out in front” of its clientsand to invest almost counter-cyclically.

“We didn’t significantly decrease our investments in2009 from 2008,” he said. “Our asset-light business modelallows us to take advantage of the cycles in our industry.We are going to the other seismic vendors to get vesselcapacity. We can get it for lower cost because of the mar-ket, and I can continue to invest in multiclient data andthen be prepared for the upswing when it comes.”

Overcapacity in the market is good not only for TGS,Hobbs said. “We like it when we see these companiesannounce new vessels on the market because it gives usmore capacity to utilize,” he said. “But it’s also a sign thatthose companies have a positive view on the marketplace– they believe demand for seismic is going to increasegoing forward.”

SURGES AHEAD

The BOS Arctic heads

to the North Sea for the summer.

(Photo courtesy of Bergen Oilfield Services)




MacondoAs the global financial situation began to stabilize, theindustry as a whole was starting to view 2010 with at least a faint ray of hope. That changed on April 20 when theMacondo well in the GoM blew out, killing 11 people andcausing the worst environmental disaster in US history.

The Obama administration acted quickly to repeal ear-lier claims that licensing rounds would be held in the east-ern GoM and the East Coast of the US and declared adrilling moratorium in the deepwater GoM. This had animmediate near-term impact on the geophysical industry.

Even companies that had no activity in the GoM felt theimpact. “Since 2009, we haven’t been in the GoM, so wehaven’t been relying on that business,” said Jan Søvik, vicepresident of marketing for Bergen Oilfield Services (BOS).“But it has affected the vessel availability, meaning that anumber of seismic vessels have been pulled out and havebeen spread to other markets. That’s putting pressure onprices and availability of work in other markets. So indi-rectly it has affected us.”

Companies active in the GoM had considerable fallout.“Uncertainties in the Gulf shaped multiclient sales in2010, which were below typical levels until the fourth quarter,” said Ribadeau-Dumas, adding that this uptickwas driven by a renewed interest in activity despite theongoing uncertainty. In fact, several companies’ 4Q 2010earnings were far above analysts’ expectations, drivenmostly by multiclient sales.

Added Reksnes, “The event led to a halt in the oil com-panies’ purchasing of seismic data for some time. Theirwillingness decreased significantly to prefund new surveysin the deepwater areas because they didn’t know thefuture conditions.

“Also, the incident has increased the attention opera-tions connected to oil and gas exploration get in the pub-lic domain, especially the HSE elements.”

WesternGeco continued to explore in the GoM becauseits clients were enthusiastic about its dual coil project, saidKotochigov. “They signaled that they had confidence inour capabilities and would continue to support us,” hesaid. “We appreciate that for our clients in the Gulf ofMexico it was a challenging year that will take some timeto work out. However, the Gulf of Mexico is recognized asone of the world’s major basins, and its long-term impor-tance to the domestic economy is not in doubt.”

This is being expressed by clients which, based on the4Q 2010 results of CGGVeritas and others, are signalingtheir continued interest in the area through their wallets.Ribadeau-Dumas noted that WAZ prefunding and salesremained active throughout the year. “This highlights thelong-term confidence in and importance of the deepwater

Gulf of Mexico to the industry and the value that wide-azimuth brings to exploration and production,” he said.

“It’s interesting,” added Hobbs, “because oil companies,while they’ve been very cautious about the GoM, are stillbuying seismic data there. That says they’re taking alonger-term view.”

This is a sign of preparedness for when normalcyreturns, so oil companies are buying seismic data andmaintaining employment levels for geologists and geo-physicists, he said.

The view for 2011Even without unrest in the Middle East and North Africa,which likely will put upward pressure on oil prices (whichoccurred after these interviews were conducted), geo-physical contractors in general seem bullish on 2011and beyond. According to Kotochigov, 2011 will be a busyyear. “We see a high level of bidding activity in the indus-try, and we have a confirmed backlog through 3Q 2011. In fact, as expressed as quarters of activity, the global seismic backlog is the highest it has ever been.”

For CGGVeritas, the year could partially restore the driv-ers that pushed oil prices so high in 2008. “We see globalenergy demand at peak levels, low reserve replacementsrates, complex and challenging exploration opportunities,and maturing reservoirs,” said Ribadeau-Dumas. “In theface of these challenges, most analysts estimate that E&Pspending will increase in 2011, with exploration and seis-mic spending outpacing the general trend.”

He added that he expects the marine market to be uparound 20% over 2010, and it will continue to strengthen


New processing techniques like reverse time migration have rev-

olutionized the marine seismic industry. (Image courtesy of TGS)



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in most regions, though not necessarily the GoM. Søviksaid BOS will be active mainly in the Middle East and Asiawhile wrapping up a survey in the North Sea and planninga return to West Africa. Many companies also are tenta-tively targeting the Arctic.

“The Arctic is an area that has not really been solved,”said Tim Rigsby, senior vice president, Strategic Initiativesfor ION Geophysical. “It’s a challenging area to operate

in, and it’s an area where oil companies have a tremen-dous need for data. To help companies get the data theyneed, we developed proprietary technology that allows forin-ice acquisition. Using this technology, we’ve expandedtraditional acquisition boundaries into new territory andextended the shooting window far beyond what was previ-ously possible.” ION’s Arctic data library now containsmore than 30,000 miles (50,000 km) of data across theCanadian Beaufort and US Chukchi seas as well as north-east Greenland.

Polarcus brings DNV-acknowledged arctic procedures tothe area and winterized vessels with high ICE-1A Class. It is the only seismic company in the industry with 3-D vessels less than 20 years old that carry this class notation.On order, with delivery early in 2012, are two new 14-streamer seismic vessels, which will incorporate ICE-1A(super ICE-Class) capabilities.

Technology leads the wayIt has been refreshing for these companies to see theindustry’s consistency in its interest in new technologiesdespite the downturn. One of the key technologies citedby many players is increased bandwidth.

“The benefits of acquiring broadband marine seismicdata have long been accepted, but until recently this hasbeen difficult, if not impossible, to achieve,” Ribadeau-

LEFT: CGGVeritas’ Oceanic Vega shoots a WAZ project in the

GoM. (Image courtesy of CGGVeritas)

ABOVE: Technicians work in the recording room during a dual

coil operation. (Image courtesy of WesternGeco)



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Dumas said. “Today, new equipment, techniques in acquisition, andadvances in imaging technology have overcome most challenges.”

Obtaining a larger range of frequencies also is desirable, Ribadeau-Dumas said, because broad bandwidth produces sharper wavelets for betterresolution. Several companies have introduced broadband solutions:

• CGGVeritas’s BroadSeis solution combines equipment with novel acquisi-tion geometries and proprietary processing algorithms to produce bettersubsurface images;

• WesternGeco offers DISCover, a full-offset broadband solution; and• PGS has its GeoStreamer cable system and now is working on a new

source technology that applies similar de-ghosting techniques on thesource side. The end result, Reksnes said, is increased amplitude in thelow and high frequencies.

In addition to streamer techniques like WAZ surveys, ocean-bottom cableand nodal systems also are gaining favor. Shell recently showcased a newtype of autonomous underwater vehicle that can be preprogrammed toplace sensors on the seabed, eliminating the need for costly ROVs.

But better data require better processing, and many see this as an areathat will undergo major improvements in the next few years. “We believethat the new acquisition technology will be followed by processing technol-ogy, taking advantage of the increased bandwidth and the ability to use boththe up- and down-going wavefields in imaging and multiple removal,” Rek-snes said.

Huasheng added, “Imaging is a continuous R&D program. Reverse timemigration (RTM) and RTM with anisotropy algorithms will become a stan-dard migration.”

At TGS, one of the ways it stays ahead of its clients is through interpretingits own data, and this requires advanced processing. “Where we differenti-ate the quality of our product is in the processing of the seismic data,”Hobbs said. “That’s when you assure the quality; that’s when you make surethat what you give the client is error-free and the highest resolution that youcan deliver. If you look industry-wide, most of the technology advancementand differentiation has been on the processing side of the business.”


The marine market still lags behind land in all regions. (Graph courtesy of World

Geophysical News)


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TGS and others also are taking advantage of advances incomputer technology, and an exciting recent move is shift-ing the processing from central processing units to graph-ics processing units (GPUs). “Right now we’re movingtoward doing more of our RTM on GPUs,” Hobbs said.“The improvements in speed have been quite impressive.”

A wild ride, as alwaysGeophysical contractors are no strangers to difficult mar-

ket conditions, and these past few years again have chal-lenged them to face down tough problems. But somethingseems different this time, and it is possible that oil and gascompanies finally are in sync with their seismic contrac-tors, paying a premium for new technologies even in thedarkest times because they know these technologies willget them closer to the answers they need.

R&D has not taken a backseat to survival, and the resultstruly are paying dividends.

The marine seismic industry was not the only industrystruggling through the recession. Companies offer-

ing electromagnetic (EM) services have been strugglingas well. In many ways the two services are similar, but insome ways they’re very different.

Dave Ridyard, president of EMGS Americas, said 2010was only better than 2009 because 2009 was “a cata-strophic year.” Unlike seismic, which is a widelyaccepted technology, the jury is still out on controlled-source EM (CSEM) data, which its proponents claim canimage direct hydrocarbon indicators in the subsurfacedue to resistivity contrasts. It also is a rapidly developingtechnology.

“When times are hard, oil companies have an under-standable tendency to limit expenditures to the tech-nologies they know best. People in the oil industrybelieve in a technology when people have drilled wellssuccessfully based on it,” Ridyard said. “If you thinkabout wells that companies are announcing results for inthe past 12 months, they were probably doing the EMwork in 2005 or 2006. You are talking about peopleassessing a technology based on its state of the art fouror five years ago, and at that point it was two years old.”

The technology has picked up since then, and by 2008 EMGS had a 3-D product and an anisotropic inver-sion product. “We felt like the technology was just start-ing to pick up. But it’s taken a hiatus because of thefinancial crisis.”

Added Richard Cooper, CEO of RSI, “Although com-mercial pickup is slower than we would like, this is to beexpected given the relative immaturity of the technol-ogy compared to seismic, the conservative nature of theoil and gas industry regarding new technology, and thecurrent economic climate. However, we believe carefulapplication of CSEM technology will lead to satisfiedclients, repeat business, and growth in the acquisitionmarket.”

Given the newness of the technology, EM companieshave a rather odd business cycle. Companies will shoot a survey and wait for the results. If they are not happy with the results, they won’t necessarily abandon the concept altogether, but they will not be immediate returncustomers.

Companies that are happy with the results, on theother hand, examine their existing portfolios and asktheir EM provider to acquire a multitude of surveys overthis acreage to help de-risk drilling prospects.

“All of a sudden, that customer becomes our biggest customer for 18 months,” Ridyard said. “Then, whenthey’ve worked their way through the backlog, it dropsoff to steady state.”

EMGS is teetering on the decision to launch a thirdboat, in part driven by its intention to continue to growthe multiclient market. Already it has shot two wide-azimuth 3-D surveys in the Barents Sea and two more inthe Gulf of Mexico, and it has plans for other parts of theworld as well.

“The economy of scale of doing 3-D seismic on a largescale allowed the data to get into the hands of mid-sizedand small companies,” Ridyard said. “I think we’re start-ing to see the beginning of that same process – this canactually be used as a frontier exploration tool rather thanjust a drilling de-risking tool.”

Cooper disagrees. “CSEM in its current form is bestused for reservoir characterization and appraisal,” hesaid. “It’s good at answering questions such as, ‘Is the tar-get reservoir charged? What is the lateral extent of thereservoir? What are the saturation levels?’ This is simplya fluid substitution question. Can we measure the resis-tivity anomaly induced by the presence of hydrocarbonsagainst a background response? In frontier areas, wedon’t know the background with sufficient certainty, andtherefore we cannot reliably and robustly interpret anyanomalies we detect.”

EM industry holds its course



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The primary inputs to drilling planning and executionare from seismic and well data. An earth model con-

sisting of structural information with geological targetsand faults and with relevant formation properties suchas pore pressure and fracture gradient guide drillingdecisions to help place the well in the right “geological”target and to avoid drilling hazards. The best possibleaccuracy and resolution at the well location is required;therefore, all available informationneeds to be optimally combinedand used with the latest model-building and imaging technologies.

The lack of adequate technolo-gies and measurements, along withturnaround time limitations, havemade this type of optimum use ofseismic and well data (predrill andwhile drilling) impractical untilnow. Recent developments inmodel building, new rapid andmore accurate imaging technolo-gies, and the availability of newwell measurements are makingthis optimum combination more of a reality. This newapproach, seismic-guided drilling (SGD), has been usedin a Gulf of Mexico (GoM) well, demonstrating thepotential value it can provide to drillers.

Components of a seismic project for drillingThree key components of this approach differentiate itfrom other applications. The first is a small volume ofinterest. An earth model relevant for drilling a particu-lar well covers a volume that includes the planned welltrajectory and possibly neighboring locations with wellor geological information – the drilling volume of inter-est (DVI). The size of the DVI typically is much smallerthan that used for other seismic applications such as

regional imaging. The relatively small data volumeallows the rapid use of sophisticated techniques to buildand update the best possible high-resolution earthmodel in the DVI.

The second component is integrating well informa-tion. In a drilling project, there is at least one well – i.e., the one being drilled – in addition to any offsetwells. Availability of new well measurements, such ascheckshots and vertical seismic profiles (VSPs) whiledrilling, and technologies that can optimally integratethem with seismic information to constrain the localearth model, such as well-constrained tomography, arecritically important.

The final approach is a fast turnaround time – “intime” for drilling decisions. The turnaround time ofearth model building/updating and reimaging needs to be performed in the driller’s time scale, in time fordecision-making for both baseline and while-drillingupdates. New high-end imaging algorithms such asGaussian packet migration that can handle complicatedgeology and produce rapid remigrations are required.

Drilling challenges Seismic information cannot address all of the challengesdrillers face, but seismic data can help with a number ofimportant ones. One area is better well placement.

New integrated seismic technologyimproves well placement

The full potential of seismic data for drilling applications is increasingly being realized byadvanced earth model building and new rapid imaging technologies.

Cengiz Esmersoy, Annabelle Kania, Andrew Hannan, Lee Lu, Sharon Teebenny, and Ling Duan, WesternGeco;

and Arturo Ramirez, Schlumberger

The SGD project execution consists of three phases: feasibility, drilling baseline model, and

while-drilling updates. (Images courtesy of WesternGeco)

43-48 EXPSUCCESS-westerngeco_43-48 EXPSUCCESS-westerngeco 3/23/11 4:58 PM Page 43


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This includes: • Reducing uncertainty in the location of drilling

targets, including casing points, faults, and targetreservoir(s);

• Quantifying uncertainty of drilling target loca-tions; and

• Improving reservoir property and structure defini-tion through inversion.

Seismic data also can help avoid drilling hazardsthrough shallow hazard identification improvements,pore pressure and fracture gradient estimates, reduc-ing and quantifying uncertainties in estimates, andidentifying other regional hazards such as tar and gashydrates.

Project executionAn SGD project starts with identifying challenges andrisks expected when drilling a particular well. A base-line earth model is constructed, and the model isupdated while drilling. There are three phases of proj-ect execution.

During the feasibility phase, candidate solutions andtechnologies (e.g., the type of required

migration/inversion techniques) for the expecteddrilling challenges are identified. Existing seismic, offsetwell data (if available), and other reference informationare analyzed to determine if they are appropriate for theproposed techniques. Illumination studies are con-ducted for the key drilling targets. Uncertainty measuresregarding the structures, fault locations, and drillinghazards are evaluated. This phase ends with a go/no-gorecommendation based on whether project objectivescan be met.

The best possible earth model with all predrill informa-tion available is constructed in the drilling baseline phase.This model serves as the starting point for while-drillingupdates in the next phase. The drilling baseline earthmodel includes an anisotropic local velocity model, adepth-migrated high-resolution image, interpreted hori-zons and faults, and drilling hazard estimates.

The final phase is the while-drilling updates phase. Asthe well is being drilled, new local information becomesavailable for updating the earth model in the DVI. Thisis particularly valuable in an exploration case, where lim-ited or no nearby offset well data are available.

Updates, including pore pressure and fracture gradi-ent estimates, are done on a predetermined schedule oras required. Real-time LWD data (checkshots and logs)are used for while-drilling updates. Recorded-modeLWD and intermediate wireline VSPs and logs are used

The panel on the left shows the legacy image that existed prior to the

GoM project. An anisotropic velocity model was built using the offset

well (Well B) data, and seismic data were depth-migrated. The panel

on the right shows the result giving the best possible predrill image

at the baseline stage. There was a significant (>750-ft or 230-m)

depth shift in the new image compared with the legacy image.

In a GoM well (Well C), a primary challenge was to place the

135⁄8-in. casing below a secondary fault. This was necessary for

the hole size requirements in the final well completion. Locating

both primary and secondary faults accurately was deemed crit-

ical. Large uncertainties were expected in the positioning of

events using the existing seismic image. It was important to

improve the velocity model and reimage while drilling to reduce

the positional uncertainty of the fault locations.



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to update the model and the image between bit runs.Local anisotropic velocity updates are obtained using

reflection tomography with check-shots and/or well tops used asconstraints so the model is consis-tent with well data and seismicinformation. The structural depthimage is updated by rapid remi-gration enabled by massively par-allel computing resources. Recentdevelopments in algorithms suchas Gaussian packet migration havefurther decreased the turnaroundtime for these remigrations.

In one example, LWD, check-shot, and wireline data wereacquired up to the mudline tocomplement the offset well for agood velocity model. Anisotropicvelocity models were created inseveral stages by seismic tomogra-phy where the vertical velocitieswere constrained by well data.The volume for velocity modelsincluded the offset well to ensurea proper tie to that well in addi-tion to the new well.

For each updated model, sur-face seismic data were reimagedwith an updated model duringdrilling, enhancing fault locationaccuracy to impact drilling andcasing decisions. The desired cas-

ing location was predictedwithin +/- 50 ft (15 m). Theprediction was performed usingreimaging performed while thedrill bit was approximately1,500 ft (458 m) above theplanned casing depth.

Drilling planning and execu-tion can benefit greatly from anaccurate high-resolution earthmodel obtained from seismicdata integrated with well infor-mation. Using recent develop-ments in rapid and accurateimaging technologies and theavailability of new well measure-ments, SGD allows this earthmodel to be regularly updated

while drilling the well, enabling optimum well place-ment and drilling hazard management.

The panel on the left is the legacy image that existed prior to the GoM project. The panel on

the right is the seismic image after the final update.


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Independent oil and gas companies are an integral ele-ment of global exploration. From the Gulf of Mexico

(GoM), where independents are the largest sharehold-ers, and the US shale plays, where smaller E&P compa-nies continue to lead the way, to the success of UKcompanies such as Tullow Oil and Heritage Oil inUganda and Cairn Energy in India, independents are the first movers.

Emerging plays that are proving to be particu-larly hot areas for independents include theAlbertine Graben in Uganda, the Tano Basin inGhana, the Zagros Mountains in Kurdistan, andnew plays in more mature areas, such as the UKand Norwegian North Sea.

Commercial success rates also continue toremain steady despite the growing geologicalcomplexities and remoteness of some targetregions. A recent 2010 survey by RichmondEnergy Partners of 27 mid-cap independentsfound commercial success rates are approxi-mately one in three. The same survey found thatthese independents generate US $3 in value fromevery $1 invested in exploration.

However, despite these successes, the odds stillare stacked against independents compared totheir more deep-pocketed rivals, the E&P majors.

Independents have an understandably lowerresource threshold for exploration and investmentand, with frontier regions ever more complex andremote, have to invest in new technologies andtake on increased risk in exploration activities.

Furthermore, if proposed US legislation thatwill increase offshore liability limits comes intoforce, many independents that do not have thecapital to meet new government requirements

will have to turn away from the GoM and focus on newfrontier regions, increasing the competition.

How can risk be better managed for independents intheir oil and gas exploration activities? How can inde-pendents better define their acreages for potentiallicensing?

SeismicFor the majority of independents, 2-D and 3-D seismiccontinue to be the technologies of choice, both onshoreand offshore. It is through seismic and the accurate illu-

GGI helps level the playing field for independents

Independent oil and gas companies today are a major driving force behind exploration activities.

Phill Houghton, ARKeX

The Albertine Basin is relatively unexplored but has good

hydrocarbon potential. (Images courtesy of ARKeX)

49-52 EXPSUCCESS-arkex_49-52 EXPSUCCESS-arkex 3/23/11 4:58 PM Page 49


mination of the subsurface that firm target locations fordrilling can be decided upon.

The cost of untargeted seismic over large areas, how-ever, can be extremely expensive and logistically chal-lenging. In areas such as the dense forests of theDemocratic Republic of Congo, the mountains ofNorthern Algeria, or in offshore fields where technolo-gies such as wide-azimuth surveys (requiring as many as four vessels) are becoming increasingly popular, it is not practical to rely solely on seismic and the costs,large-scale infrastructure, lack of targeting, and longturnaround times that accompany it.

New technologiesIt is into this arena that new technologies are emerging– geophysical techniques such as non-seismic data acqui-sition and geological techniques that focus on the litho-logical, stratigraphic, and structural elements of targetreservoirs.

One key technology is gravity gradiometry imaging(GGI), which maps the small density variations in under-lying rocks by measuring the gradient of the earth’sgravity field. GGI provides an increased signal-to-noiseratio and wider bandwidth than conventional gravitymeasurements. In addition, its ability to include offlineor sideways geology in its datasets also can help reducethe uncertainty in 2-D measurements and provide

enhanced interpolation solutions between sparse acqui-sition lines.

The non-invasive nature of GGI; its ability to qualifyvast regions quickly, accurately, and cost-effectively; andthe fact that GGI can optimize the design of future seis-mic surveys are proving particularly attractive to today’sindependents.

This optimization of survey planning through GGIhelps independents focus on the most efficient solutionfor enhanced illumination and directs the survey towardthe most potentially prospective areas.

GGI in the fieldSeveral independents are using GGI to better focustimelines, budgets, and future seismic surveys/drillingprograms by generating the best available picture of theacreage beforehand.

Forent Energy Ltd. is a Calgary-based oil and naturalgas producer pursuing a combination of short-termheavy oil production growth in Western Canada andhigh-reward pioneering exploration opportunities inNova Scotia.

The company has used GGI as a cost-effective methodto image the subsurface of its Nova Scotia prospect area,leading to the more efficient placement of its 2-D seis-mic lines and also having minimal landowner impact.

Forent is the largest onshore landholder in Nova Sco-

A 3-D perspective view of gravity

gradiometry anomalies exhibits

reef geometries and areal

extents in Nova Scotia.




tia, with exploration rights to 1.1 million acres that are prospective forreef oil in Shubenacadie Basin and shale gas in St. Mary’s Basin.

On behalf of Forent, ARKeX conducted a high-resolution 340-sq-mile (890-sq-km) geophysical imaging program in the ShubenacadieBasin during the second half of 2010, consisting of gravity gradiome-try as well as magnetic and LiDAR datasets.

The target was the Alton Block, a 740,000-acre petroleum and natu-ral gas holding that encompasses two oil and gas reef-prone fairwayson the south portion of the block. The area was described by petro-leum consulting company Sproule Associates in 2008 as having “allthe parameters required for a viable petroleum system ... and, if delin-eated through the proposed geotechnical methods, should providemedium- to high-risk exploration targets.”

The program was designed to identify possible subsurface GaysRiver reefal structures that were anticipated to be hydrocarbon-bear-ing. Interpretation of the GGI data identified more than 16 anom-alies, demonstrating similar geometries to modern reefs andexhibiting areal extents resources assessment. These areas will be delineated further through a 2-D seismic program in 2011.

More than 7,000 miles (11,265 km) away, Tower Resources, a UK-based independent oil and gas exploration company, has been usingGGI to improve structural definition within a proposed license area innorthwest Uganda along the East African Rift System. Fewer than 200wells have been drilled to date in the East African Rift System, whichcovers an area of 887,880 sq miles (2.3 million sq km), pointing tomuch untapped exploration potential.

In Tower’s case, the GGI data are helping to improve the planningfor a 91- to 122-mile (150- to 200-km) 2-D seismic program – to takeplace in the next few months – by mapping structures in the deeperpart of the basin to improve structural definition and assist in identify-ing a better developed reservoir section.

The airborne GGI survey took place over the Block EA5 RhinoCamp Basin, a 1,124-sq-mile (2,941-sq-km) license area at the north-ern end of the Albertine Graben. The basin is relatively unexploredbut has good hydrocarbon potential, with various analogies to theother producing basins within the Albertine Graben. Covering thewhole area through seismic, however, would be a challenge, and anexpensive one at that, as it incorporates the Nile River and swamps.

The survey has confirmed the presence of a deep potential sourcekitchen as well as previously undefined structures. Tower’s boardbelieves that the apparent volume and depth of the kitchen are suffi-cient to generate enough oil to fill a commercial-sized trap and thatthe new target area is sufficiently large and well-defined to containrecoverable resource potential of more than 100 MMbbl.

The new insight into the geology and high-resolution measure-ments that GGI has generated will ensure future seismic work forTower can be located with greater confidence, with the survey refinedto focus on the most prospective areas.

Whether it is applied to licensing, frontier exploration, matureplays, or prospect generation or evaluation, GGI is a powerful de-risking tool and a driving force in independents’ E&P efforts.


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LANDSEISMIC

Land 3-D seismic surveys require hundreds of tons ofstate-of-the-art electrical equipment, large crews, and

many vehicles to be distributed over tens to hundreds ofacres of farmland, mountains, factories, and suburbs forseveral months. Being too conservative in the surveydesign can lead to a significant increase in the distur-bance and the HSE exposure as well as reducing theeconomic rate of return. The goal is to design a “fit-for-purpose” survey that ensures the data adequately imagethe subsurface and are suitable for reservoir propertyprediction while minimizing environmental impact and cost.

Basic conceptsSeismic surveys are like sonar on steroids. They arebased on recording the time ittakes for sound waves generatedby controlled energy sources, suchas Vibroseis trucks or buriedexplosives, to travel through thesubsurface and reflect off geologi-cal boundaries within the earthback to the surface.

The seismic energy generated ateach source location (shot-point orSP) is recorded simultaneously by apatch of several hundred to severalthousand recording instruments(receivers or geophones). Take, forexample, the concept of seismicenergy from one SP beingrecorded by one receiver. Theenergy generated at S travelsthrough the earth, reflecting fromeach geological boundary at themid-point (CMP), and recorded atR. The amplitude of the seismicenergy is recorded every 1 or 2 msfor up to 10 seconds, and the datas-tream from each receiver location is called

a trace. The traces from all the receivers are thengrouped to form a “shot gather.”

A typical survey consists of thousands of shot-pointsand thousands of receiver locations. Many source-receiver combinations have the same mid-point, and thedata can be re-sorted to create a “CMP gather.”

For many years, 3-D seismic land surveys consisted of a“live patch” of six to eight receiver lines due to restrictedequipment capabilities; such a patch requires 1,920channels. For a shot fired in the center of this narrowpatch, the offsets recorded would be 2,625 ft (800 m) inthe cross-line direction and 9,843 ft (3,000 m) in the in-line direction, resulting in poor azimuthal coverage forthe larger offsets.

The 19,686-ft by 19,686-ft (6,000-m by 6,000-m) livepatch is the ideal as it provides full azimuthal coverage atall offsets, but it requires 7,200 channels, stretching thelimits of many contractors.

Land 3-D seismic survey designed to meet new objectives

When the need for higher channel count and better imaging bumps up against a requirementfor greater environmental stewardship, planning land seismic surveys can be a balancing act.

Jon Cocker, DownUnder GeoSolutions

A three-layer model shows the modeled seismic response. (Images courtesy of DownUnder

GeoSolutions)

53-55 LandSeis-DUG_53-55 LandSeis-DUG 3/23/11 4:58 PM Page 53


LANDSEISMIC

Main steps in survey design There are four steps in designinga successful survey. The first stepis to clearly identify the objectives,restrictions, budget, and timing.Many questions need to beanswered at this stage.

Are the data used for basicstructural interpretation, ampli-tude/inversion studies, or reservoir monitoring (4-D)?What resolution is required? When are the datarequired? What is the budget, and is there any flexibil-ity? Are there any environmental restrictions? Clarity onthese questions allows the survey designer to focus onthe pertinent issues, i.e., will seismic be able to predictfluid and lithology for the target depth and expectedfluid properties? Does the geological boundary have suf-ficient reflectivity? What offsets are required?

The second step is to identify the issues in existingdata or acquire test data. Previous seismic surveys in thearea are an invaluable resource to improve understand-ing of data quality, frequency content, noise issues, etc.,to aid in the design process. Seismic source and receivertests are recommended if no data have been acquiredpreviously or if significant improvements are requiredfrom the existing data.

Step three is to design the survey. Information such asprevious seismic survey data and reports, velocity pro-files, well logs, target depth(s), maximum dip, andexpected fluid properties are needed to optimize the 10 main survey design parameters:

1. Source type (explosives, weight drop, or Vibroseis)– Explosives generate the highest data quality andcan be used in even the roughest terrain, but theyrequire long lead times and can be expensive.Vibroseis is significantly cheaper in most situationsbut offers lower data quality per source point; italso requires a lot of land to be cleared and can beused only on relatively flat ground.

2. Receiver type – There are many options, but thedecision generally is whether to use single geo-

phones or geophone arrays (multiple geophonesjoined together to boost the signal). Large analogarrays are used when there is significant random orcoherent noise. Arrays also can be created digitallyusing single geophones by summing the data dur-ing the processing stage. This can be preferableover analog arrays but requires a smaller receiverinterval and hence the ability to record data frommore receivers simultaneously.

3. Maximum offset (source-to-receiver distance) –The velocities and density of the target/subsurfaceare used to model the amplitude of the reflectionevent versus offset to determine which offsets arerequired for imaging and lithology/fluid predic-tion. The maximum offset required generally isaround 11⁄2 to two times the target depth.

4. Maximum bin size – Bin size is chosen to ensurethe wavefield is sampled sufficiently to avoid dataaliasing. It is dependent on the frequency contentof the data, maximum dip, target depth, and veloc-ity.

5. Source interval – This should be no more thandouble the maximum in-line bin size.

6. Receiver interval – This should be no more thandouble the maximum cross-line bin size. It alsoneeds to be small enough to sufficiently sample the noise.

7. Source line interval – The source line intervalmainly affects the distribution of the smallest off-sets recorded in each bin. The minimum offsetshould be less than the target depth.

8. Receiver line interval – As for the source line inter-

A 3-D seismic source and receiver line lay-

out can have two different live receiver

patches. This survey would consist of

21,600 receiver locations and 8,880

source locations that need to be surveyed

and pegged and would require approxi-

mately 600 miles (1,000 km) of track and

890 acres of land to be cleared.

53-55 LandSeis-DUG_53-55 LandSeis-DUG 3/23/11 4:58 PM Page 54

val, the receiver line interval minimum offsetshould be less than the target depth.

9. Live patch dimensions – This terminology refers tothe length and width of the patch of receivers thateach shot is recorded into. This controls the maxi-mum offset recorded, offset distribution, azimuthalsampling, and cross-line fold. The number ofreceiver lines in the patch andreceiver line interval need to beoptimized together to ensure thepatch width is at least half thepatch length. The patch size islimited by the number ofreceiver channels available.

10. Migration aperture – An extrafringe of data needs to beacquired around the target to capture all the required information.

Several survey designs that meetthese technical requirements shouldbe created to enable the cost ofdrilling, contractor capabilities, ter-rain, environmental, and logisticalrestrictions to be incorporated intothe tender process.

The final step is to fine-tune thedesign to match the geography, infra-structure, and environmental restric-tions. Once the basic surveyparameters are finalized, the designneeds to be fine-tuned to ensure thatthe planned locations match what isrealistic and sensible. There are manyreasons why a source or receiver pointcannot or should not occupy a pre-planned location; for example, theyare too close to a well or facility.Changes also can be made to reduceimpact, i.e., a source line could bemoved to make use of an existingtrack or avoid rare flora. High-qualityaerial photos and maps/shape files ofroads, rivers, wells, power lines, etc., are invaluable at this stage.

Allocating sufficient time andbudget and using a suitably experi-enced geophysicist to make these deci-sions and design a fit-for-purposesurvey are critical. Adjusting thedesign to maintain the technicalrequirements while accounting for

all of the constraints requiresan understanding of how each componentwill affect data processing and interpreta-tion. There needs to be flexibility in the budget to allowthe survey design to deviate from previous designs thatdid not meet the objectives.


For more Land Seismic

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In 2009, ExxonMobil shot one of the largest land seis-mic surveys ever conducted. An 82-sq-mile (212-sq-

km) high-effort compressional (P)-wave survey housed asmaller high-effort 3-D/three-component (3-C) survey,and within that was a smaller static patch.

Overall, the survey had more than 78,000 live chan-nels; 890,000 work hours; 18,000 hours of HSE training;as many as seven helicopters operating at once, complet-ing 9,279 flights; and as many as 300 people on theground driving vehicles that logged more than one mil-lion miles (1.6 million km).

The questions now are, “Did it work?” and “Was itworth the time, cost, and effort?” ExxonMobil geoscien-tists took delivery of the P-wave data in January 2011.They are hesitant to crow too loudly, saying repeatedly,“The jury’s still out.” But their excitement is palpable.

Piceance CreekThe survey was conducted over part of ExxonMobil’sPiceance Creek asset, a field the company has owned formany years. This asset is a tight gas field that has beentreated routinely as a statistical play. The hope was that abetter understanding of the subsurface might lead to amore successful drilling program.

“If we can do something to increase the odds that anindividual well will be a better producer, then we caninfluence the overall statistics of those plays and gainvalue,” said Dave Johnston, geophysics coordinator forExxonMobil Production Co. “We put a lot of effort andmoney into acquiring this survey, but it will add value tothe field over a very long period of time.”

Seismic challenges in the field are numerous. Imagingthe near surface is difficult, the topography is rugged, acreek valley causes attenuation in the data, and a bakingsoda-like material called nacholite creates a scatteringmedium that reduces data quality.

To pull off a survey of this magnitude also was difficultbecause much of the equipment did not exist. “We ini-tially wanted to do a 44-line rolling spread when we wentout to bid,” said John Hefti, geophysical associate forExxonMobil Exploration Co. and seismic processinglead on the Piceance project. “But nobody could do it.”He added that it took more than a year to secure theequipment before the survey could commence.

Finally, the acquisition window was narrow. GlobalGeophysical Services crews could not begin until lateJuly and had to be finished by December. Vibroseistrucks were restricted to the roads, so helicopters wererequired to transport equipment to drill shot holes fordynamite sources. Additionally, the very noisy environ-ment due to traffic and facilities and the delicate ecosys-

tem made this not a normal, run-of-the-millseismic survey.

P-wave resultsBrute stacks from the field were not promis-ing. Hefti said one data example showednothing but noise. “We wondered whether we were actually acquiring any signal at all,”he said.

Working with proprietary ExxonMobil algo-rithms and those employed by WesternGeco,


LANDSEISMIC

Piceance Creek pushes the land seismic envelope

A massive survey has resulted in a dataset with many surprises.

Rhonda Duey, Senior Editor

Because of rugged terrain, a fleet of seven helicop-

ters was required to transport people and equip-

ment. (Images courtesy of ExxonMobil)

56-59 LandSeis-Exxonmobil_56-59 LandSeis-Exxonmobil 3/23/11 4:58 PM Page 56

which did the data processing, Hefti’s team spent ninemonths removing noise from the data. “It’s like peelingback the layers of an onion and removing small bits ofcoherent noise in multiple domains so that we’re notclobbering it with a hammer and removing signal,” Heftisaid. “We do this to remove the noise and preserve thesignal and the amplitudes to perform quantitative attrib-ute analysis and inversion on the gathers and stacks.

“It was a lengthy iterative process, but I think we got adecent product.”

So far, the 3-D P-wave prestack time-migrated data isexhibiting better fault definition, higher seismic fre-quency, better positioning, and a greater level of strati-graphic detail at reservoir level than previous data. “TheP-wave data has given us a lot more information than wewere originally expecting,” Hefti said. “We’re able to mapout a fault network, and we’re seeing areas that correlateto lower pressure and others to more water. It’s given us alot of insight into what’s going on in the field.”

Added Johnston, “The relationship drawn between thestructural framework of this area and the productivity ofthe wells is a key learning, and it could very well affecthow we proceed with the development of the area.”

Converted wavesProcessing of the converted-wave data currently is underway. Hefti said originally a three-interval layer strippingapproach was used to analyze azimuthal anisotropy, butinput from interpreters has led the team to adopt a nine-layer approach that is more geologically accurate. “When

we performed this analysis on the prestack data, we wentfrom something looking random to everything cominginto focus very sharply,” he said. “To me, this is incredible,and it reinforces that we’re on the right track in under-standing the anisotropy.”

He added that where well information indicates frac-ture direction, the new seismic data agree with thoseresults.

Naturally the asset team in charge of Piceance is inter-ested in seeing additional results from this survey. ButJohnston said that it has a research component as well.“There’s a lot of very interesting stuff in there,” he said. “I think this will not only be of value to the business for


LANDSEISMIC

ABOVE: Vibroseis trucks could only operate on the roads in the area.

RIGHT: A shot hole is drilled using a heliportable rig.



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LANDSEISMIC

Processors have worked hard to reduce the noise that dominates the brute stack.

many years but will be a value to research as well.” Headded that ExxonMobil Upstream Research Co. investedconsiderable money and people into the project and thateffort has been “critical to the team.”

Another test involved a full nine-component 2-D survey,where the sources as well as the receivers include theshear components. This originally was intended to takeplace during the 3-D survey acquisition, but several com-plicating issues prevented further acquisition in a delicateenvironmental area. That test finally took place last year,reacquiring a 2-D line from 2007 that helped design the2009 3-D survey.

“We’re evaluating the data as we speak,” Hefti said.“That will be another evaluation to see if the futurephases should be acquired with shear wave sources.”

Fit for purpose?Given the sheer scope and cost of the survey and the hostof obstacles posed by the Piceance Creek field, it is possi-ble to question the rationale behind shooting this survey.Apparently some within the company questioned it aswell. But Johnston and Hefti stand behind the decision.

“This survey might have been overdesigned; it’s hard tosay,” Johnston said. “One of the things we’re investigating

is what level of effort is required in the field. Does inter-pretation at Piceance really need the high fold and datadensity that we acquired in this survey? And even if theanswer is yes, if you go to other parts of the world, youmay not need this level of effort.”

“On the other hand,” Hefti added, “I see the industry as a whole moving toward higher and higher channelcounts as the demand to extract more from seismic dataincreases. The high-end interpretation and analysis meth-ods applied to this dataset require accurate wavefield sam-pling, and the full-azimuth acquisition method employedat Piceance provides that level of sampling. I’ve never hada dataset where I could look at a suite of full-azimuthstacks at high fold,” he said. “You’re always missing some-thing, always guessing.”

Over all, the survey seems to be paying dividends.“These reservoirs are very complex,” Johnston said. “Youhave to think of them as an entire system. We’re not tryingto find an individual sand; we’re trying to find sand con-nected to fractures connected to other sands. That systemapproach is what’s needed to understand how the wholefield is going to respond and how we’re going to optimizerecovery.

“It’s a phenomenal dataset.”



LANDSEISMIC

Following the success of shale play exploitation inNorth America, interest has spread to the rest of the

world. Rising demand for energy in developing coun-tries and the quest to diversify suppliers have combinedto intensify the desire to exploit these vast, newly identi-fied unconventional resources. As shale E&P maturesand spreads, interest is focused more and more on tar-geted sweet spot drilling rather than the statisticaldrilling employed in the early stages of exploitation.

Improving successIn addition to applying the lessons learned, currenttechniques need to be improved. Development needs tobe made safer, reducing both the risks involved and theenvironmental footprint, by drilling and completingfewer, more pro-ductive wells. Also,duplicating pro-gram success from one play toanother is provingdifficult becauseshales vary in com-position, depth,thickness, perme-ability, and fracturecharacteristics.Understandingreservoir qualityand geomechanicsis critical to reduc-ing costs and maxi-mizing recovery and financial return oninvestment (ROI).

The challenge when choosing the best loca-tions to drill in shale reservoirs is to identify theareas of highest total organic content (TOC),which also will fracture easily to form good flownetworks. At the same time, it is important toensure that the fractures will be limited to thereservoir. With advanced prestack analysis of seis-

mic data, lithological (elastic rock parameters) and geo-mechanical (rock strength and stress) attributes can bederived – good indicators for TOC and fracturability.

Existing small fractures can aid production as theyprovide natural pathways that can be connected to thewell bore, but more intensive natural fracturing couldmean the hydrocarbons already have migrated away.Detailed geomechanical and lithological models of thereservoir allow both potential hazards and sweet spots tobe identified so the greatest return on drilling invest-ment can be achieved.

In today’s environment, shale operators would benefitfrom customized, comprehensive seismic strategiesdesigned to optimize resource recovery and to reducedrilling and production risks. While information fromwell bores, well logs, and vertical seismic profile data cangive a detailed view of the reservoir at the well location,combining this with advanced reservoir analysis from

Geophysical data home in on sweet spot drilling

Seismic data can be harnessed to optimize shale field production and development.

Jo Firth and Allison Branan, CGGVeritas

A workflow goes from survey evaluation and design

through acquisition and processing to detailed

reservoir analysis to produce map

volumes to identify sweet spots

to drill. (Images courtesy

of CGGVeritas)

60-64 LandSeis-CGGVeritas_60-64 LandSeis-CGGVeritas 3/23/11 4:59 PM Page 60


LANDSEISMIC

seismic data can provide detail between the wells, criticalin these very heterogeneous reservoirs.

CGGVeritas has developed a new workflow to deliverintegrated geophysical solutions offering advanced tech-nologies and services individually designed for eachproject to enhance all stages from exploration to devel-opment and production of shales. The complete work-flow recently has been applied to data library surveysover the Montney and Haynesville shales. Different ele-ments also have been applied successfully to a numberof proprietary datasets over the major shale plays inNorth America. The results of tying the geomechanicalmodels from these studies with actual gas productionfigures will be published in the near future.

Data analysisThe workflow begins with a fundamental understandingof the target through careful analysis of all available geo-logical, petrophysical, and geophysical data. This informa-tion is incorporated into a reservoir model that drives thesurvey design and acquisition parameters. Without theappropriate azimuths, offsets, and receiver/source inter-vals, it is difficult to extract the necessary lithological, frac-ture, and geomechanical properties critical for successfulshale drilling programs.

Broad bandwidth, high-density seismic data are idealfor providing the high spatial and temporal resolutionnecessary to define the thin beds and spatial heterogene-ity of shale reservoirs and create optimal reservoir mod-els. Wide-azimuth data are required for meaningfulanisotropy analysis, which is critical for stress and fracturecharacterization. Once the optimum acquisition parame-ters have been derived from the survey evaluation anddesign studies, experienced crews are available worldwideto perform the required high-quality acquisition.

AcquisitionAdvanced technologies such as point-source-point-receiver recording and mega-channel-count supercrewsusing state-of-the-art equipment and customized Vibroseissweeps can provide the broadband data to enhance shalereservoir characterization. These methods use propri-etary software to intelligently tailor Vibroseis sweeps toextend the bandwidth while working within the hydraulicand mechanical constraints of the vibrator and withoutcompromising quality or productivity. They can sweepmore than five octaves, making them particularly applica-ble for high-resolution imaging of shale reservoirs.

ProcessingCarefully tailored, reservoir-driven processing flows areapplied to the recorded data, which include advanced

Clearing the way for seismicBy Simon George, The Development Initiative (TDI)

Operation Desert Storm ended in 1991, but the rem-nants of that short but intense conflict still persist

throughout the small Gulf state of Kuwait, which saw thebrunt of the fighting. Iraqi troops were well entrenched,laying more than two million landmines while they occu-pied the country and as a result drew very intense aer-ial bombardment from the coalition forces.

Two decades later, seismic acquisition still is con-ducted on an ongoing basis by the Kuwait Oil Co., whichbrings in specialist seismic survey companies to carryout the search for the significant oil reserves beneaththe Kuwaiti desert floor. The use of vibrator trucks orcontrolled detonations presents a significant risk to thecrews if there is unexploded ordnance present.

TDI was deployed to support a leading seismicacquisition crew operating in the Menagish oil fields inKuwait. The area had a former Iraqi minefield runningthrough it as well as having been subject to numerousair strikes. Although the minefields were cleared in1993, the quality of that clearance was in doubt. TDIcarried out further clearance that uncovered six addi-tional mines.

Successful seismic acquisition programs requirespeed with data collection. The TDI clearance assetswere therefore required to structure clearance to main-tain a healthy gap between the search crews and seismiccrews. This was a task in itself, together with the veryextreme temperatures encountered, regularly exceed-ing 131ºF (55ºC) in the summer months.

Using the technique of Battle Area Clearance, a com-bination of visual and detector-aided subsurface search,TDI was able to ensure a 100% accident-free period forthe three years of the contract, during which more than1,300 items of unexploded ordnance were discoveredand neutralized.

The search teams formed an extended line andmoved through the seismic corridor. When evidence ofa cluster strike was found, the teams broke out theirdetectors and carried out a subsurface search, ensuringthat only the high-threat areas were searched.

The minefields were recleared using mine-detectingdogs operating with specialist handlers. Any positiveindications given by the dogs were then investigatedby TDI deminers, who uncovered six mines from“cleared” areas.



algorithms such as Gabor deconvolution for increasedresolution and 5-D interpolation to provide fully popu-lated common-offset vector volumes. Geomechanicalproperties are derived from careful measurements ofazimuthal anisotropy. Therefore, an amplitude versusoffset and azimuth-compliant processing flow isrequired. Depth imaging is preferable as it avoids anyanisotropy in the overburden being imprinted onto thereservoir, and it provides more reliable amplitudes.

Important lithological and geo-mechanical attributes can bederived from seismic gathers byinverting the data for compres-sional- and shear-wave velocities

and density, including Young’s modulus, Poisson’s ratio,and shear modulus. Azimuthal anisotropy analyses pro-vide information about the existing fractures, whilesimultaneous prestack azimuthal elastic inversionenables estimates of the various stress fields, such ashoop stress, closure stress, and differential horizontalstress ratio, to be produced. Understanding the stresscharacteristics provides hydraulic fracturing details,including whether fractures will form, remain open, and

Straightforward maps, identifying good

(green) and bad (red) areas to drill,

can be produced by carefully combin-

ing all the elements of the detailed

lithological and geomechanical

reservoir models.


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be limited to the desired zone. The fracture initiationpressure provides information on how much propantand pressure will be required to create the fractures.

Reservoir modelingAdvanced reservoir modeling to provide detailed litho-logical and geomechanical models is the final compo-nent of the workflow, producing a volume that combinesall of the derived attributes to identify the sweet spotsand to predict well flow rates. This detailed reservoirmodeling gives engineers a broader understanding ofthe entire field, enabling the development of more cost-effective drilling programs that incorporate informationabout directions to drill, locations of zones of interest,and recommendations for fracture stimulation toachieve the most profitable and environmentally soundproduction rates.

Microseismic services for monitoring the frac process,using purpose-designed surface layouts and in-field real-time processing, also are of use. Interpretation of thesedata allows seamless in-field adjustments based on frac-

ture direction, orientation, and penetration in and outof zones of interest to optimize fracing operations. Inter-preted data also can be used to validate and refine geo-mechanical reservoir models. Staying within zone andusing the minimum frac stages and fluids to achieve thedesired well flow can make the difference between apositive and a negative ROI.

The best lithological and geomechanical attributes are derived from seismic surveys designed to specificallytarget the reservoir and acquired and processed withthis in mind. Detailed reservoir models derived fromadvanced integrated seismic analysis provide the infor-mation engineers need to design the most productivedrilling and completion projects and therefore maxi-mize ROI while minimizing the environmental foot-print. Integrating microseismic data to fine-tune thegeomechanical reservoir models derived from seismictechnologies is providing key insights for effective explo-ration and development of unconventional reservoirsand the foundation for the move from statistical drillingto targeted, sweet-spot production.

LANDSEISMIC


Unconventional Resources and the Role of Technology OM? Dwww.eage .org E onMobil

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Typical shale reservoirs in the US, such as the Hay-nesville, Eagle Ford, Marcellus, and Woodford shale

systems, are being drilled and completed using horizon-tal well drilling technology and hydraulic stimulationmethods. This exposes large surface areas of the sourcerock to highly permeable connectors that deliver hydro-carbons to the well bore.

As a result, the shale story has two parts: horizontalwell construction and hydraulic stimulation that con-tacts the rock. Many practitioners in the field tend totreat the two parts as individual problems to be solved,but more and more people are beginning to realize thatthe two are intimately connected, and both can have asignificant impact on production.

Current practice Typical geosteering practice in shale applications is touse a low-cost drilling and evaluation system for well

placement. This usually consists of a mud motor, direc-tional sensor, and gamma ray sensor. The objective is toplace the well within a predefined section of stratigra-phy by comparing the gamma log from the well beingdrilled to an offset or type log. Where markers correlate,the stratigraphic position of the well is known.

The quality of the correlation depends on many fac-tors. A common issue is the signal-to-noise ratio of thesensor being used; a very noisy gamma log, for example,is very difficult to use for correlation. Borehole washout,along with mud properties, also can have a significantnegative effect on the ability to correlate.

Another major issue in geosteering applications is whathappens when a fault is crossed. Often, small faults are notdetected on the gamma log, and it is not until a substan-tial portion of the well has been drilled outside the targetzone that there is a realization that a fault has beenencountered. A drawback of any correlation system is thatthe well must be traversing through the section, either upor down stratigraphically, to build a profile to correlateagainst the type log. This means that if the wrong decision


Geosteering in unconventional shalereservoirs has potential

As North American shale development continually evolves, operators must determine if thereis an agreement between final production results and gamma ray stratigraphy.

Jason Pitcher, Halliburton

DIRECTIONALDRILLING

A typical total vertical depth (TVD) correlation of a vertical well log (left) is compared to a TVD log from a horizontal well (right).

(Images courtesy of Halliburton)

65-68 Drill-HAL_Layout 1 3/24/11 11:28 AM Page 65


Shale

C? Limestone

_ Sandstone

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DRILLING IN THE RIGHT DIRECTION


is made about which way to correct after a fault, a muchlonger section could be drilled out of the target zone.

A recent internal study by Halliburton’s SperryDrilling business line revealed approximately 50% ofwells geosteered using the conventional gamma ray

geosteering methods within an area of the Haynesvillewere misplaced for more than 50% of their laterallength. This was determined by using chemostrati-graphic geochemical analysis, which is very effective atdetermining the stratigraphic position of a well bore.Even with a good gamma ray correlation, results oftenare ambiguous, and the position of the well in the for-mation is uncertain, leading to misplaced wells.

When looking at the complete system of well construc-tion and stimulation, it must be determined whetherplacing the well within a specific piece of shale guaran-tees good production results. In other words, is there anagreement between final production results and gammaray stratigraphy? Many operators do not believe there is.Even operators that are getting good results now are ask-ing what more can be done on the well-constructionside to improve productivity, pushing down the ultimatecost per unit production.

Future possibilitiesBasic criteria for producing hydrocarbons from shales aretotal organic carbon (TOC) content, thermal maturity,and the stimulation potential of the rock. From a well-placement perspective, it is possible to steer according toTOC, but this usually is well-distributed in the shale inwhich a horizontal well is placed. Thermal maturity usu-ally is a function of the play and is determined well aheadof horizontal drilling. Neither of these properties is signif-icant in terms of where the well is placed within a targetinterval. A typical target can be 30 ft (9 m) thick and haveample TOC in the sequence and the desired thermalmaturity. This leaves stimulation potential as the desiredproperty affecting well placement.

A lot of work has been done from the stimulation sideon examining rocks for stimulation potential. Brittle-

ness, derived from the ratio between Young’s modulusand Poission’s ratio of the rock, is one property that isrecognized as being significant to stimulation potential.The amount of layering around the well bore also canbe a significant factor affecting the ability to stimulate

the rock. Natural fracture systems play a part in somereservoir systems as well.

The key to unlocking the potential of these plays is to determine which particular property has the most significant impact on the ability to stimulate for betterproduction. Once this property has been identified, the necessary tools can be deployed to measure theproperty not only after the well has been drilled andbefore stimulation but also in real time to assist in wellplacement. Deriving real-time brittleness and layeringfrom sonic LWD measurements and making steeringdecisions based on that data could be the game-changerfor operators struggling to realize the full potential oftheir assets.

The value of using a simple targeted suite, such as agamma/sonic suite, is realized not only through betterwell placement in more suitable rock for stimulation but also in bridging the gap from well construction tostimulation. Deciding where and how to run multiplestages in a number of stages becomes a question of goodpractice based on hard data rather than a scattergunapproach based on the notion that any frac is a goodfrac. While many operators now are leaning toward astimulation model with many closely spaced stimulationpoints, using hard data to ensure optimal placement ofthe stimulation points has not yet become commonpractice.

As shale plays continue to evolve, the value of betterwell placement will become more apparent, withfocused measurement systems that not only better posi-tion the well for stimulation but also allow for betterstimulation placement and design. Such an approachcan lead to better returns on capital spending in theform of more production of hydrocarbons per dollar,which is the ultimate metric for operators.

DIRECTIONALDRILLING

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The Permian Basin of West Texas and New Mexico is aprolific area of brownfield hydrocarbon reservoirs. It

comprises several component basins, of which the Mid-land Basin is the largest and the Delaware Basin the sec-ond largest. The Delaware Basin contains the Bone Springformation, which has been producing oil and gas fordecades. This heterogeneous formation, composed ofinterbedded sandstones, carbonates, and shales, hasenjoyed several cycles of E&P attention.

Conventional-quality sandstones were the first targets.High-rate wells were then brought in from carbonatelenses, followed by a spate of vertical drilling in low-perme-ability sandstones. Horizontal drilling now is tapping accu-mulations in thin sand formations, shales, and other tightfacies. There were more than 30 rigs working in the BoneSpring formation during 2010, targeting intervals includ-ing the Avalon shale; Leonard shale; and the 1st, 2nd, and3rd Bone Spring sand reservoirs.

Developing the Bone Spring sandsAnadarko Petroleum Corp. has been particularly active inthe 3rd Bone Spring sand, a sand-silt sequence which,although possibly eolian in source, was deposited in rela-tively deep water. As many as eight separate reservoir sandunits, typically ranging from 6 to 12 ft (2 to 4 m) in thick-ness, historically were bypassed because of lack of produc-tion in vertical wells. To produce economically, these bedsrequire maximum reservoir contact from a horizontal wellpath within a single thin layer and then stimulation tocommingle the multiple reservoir layers.

Initially, the curve and lateral sections were drilled withmud motors and geosteering decisions based on standardMWD gamma ray measurement. Initially, it took 72 days to

drill the well from spud to rig release. For maximum wellbore contact within these thin reservoirs, distinct logresponses across the reservoir are needed for lateral corre-lations and well trajectory steering. Along with many reservoirs in the Permian Basin, the Bone Spring sandscommonly exhibit low reservoir bed-to-boundary resistivitycontrasts (usually as low as a 2-ohm difference), with few, if any, features within the bed that standard gamma raymeasurements can differentiate. This has frequentlyresulted in the well bore steering out of zone, often requir-ing openhole sidetracks or long out-of-zone intervals to re-enter the reservoir.


Bed boundary mapping technologyimproves success

Rotary steerable systems combined with deep azimuthal measurements are keeping horizontal wells within the pay zone of thin, low-resistivity contrast reservoirs

of the Bone Spring formation.

Dan Geary, Gavin Fluke, Jeff DeJarnett, Callie Brehm,Kara Syvertsen, Marc Russell, Kit Clark, and Demola Soyinka, Anadarko Petroleum Corp.; Jeffrey Kok, Eric Vauter, Chad McMillan, and

John Taylor, PathFinder, a Schlumberger company; Judd Tudor, April Wisebaker,

and Stephanie Chow, Schlumberger

DIRECTIONALDRILLING

The Delaware Basin lies in West Texas and New Mexico.

(Images courtesy of Schlumberger)

69-71 Drill-SLB_69-71 Drill-SLB 3/23/11 4:59 PM Page 69

Vertical sections of Bone Spring wells encounter hard abrasive rocks and are prone to deviation from the intended trajectory while drilling. Anadarko has fine-tuned its drilling processes and bit selection method-ology to deliver time- and cost-effective solutions for thewell-construction phase. The company recognized that by using a rotary steerable system (RSS), it could acceler-ate drilling in lateral sections. It outsourced this phase ofwell construction to a specialized drilling contractor,including deployment of the Schlumberger PowerDriveX5 RSS.

Deep azimuthal resistivity measurementsTo improve horizontal drilling efficiency, Schlumbergerapplied its deep azimuthal electromagnetic resistivityLWD system, called the PeriScope bed boundary mapper.This tool makes 360-degree deep directional measure-ments that can indicate the distance to and orientation offormation boundaries 21 ft (6.4 m) from the boreholeusing a combination of tilted coil technology and multi-ple frequencies and spacings.

During drilling operations, LWD measurements aretransmitted in real time to the surface. These unique sym-metrized directional measurements, with maximum sensi-tivity to formation or fluid boundaries, make it possible tomap boundaries in real time, independent of anisotropyand dip. Real-time bed mapping and curve interpretationare performed by expert well-placement engineers withproprietary geosteering software called real-time geosteer-ing software (RTGS). The system helps to place lateralsaccurately within thin target reservoirs, reducing the

potential for costly sidetracks and improving drillingefficiency and lateral exposure in zone for optimumcompletion and production.

Beyond technologyClose collaboration among drillers, engineers, geol-ogists, and other geoscientists within Anadarko andthe service company has been a key contributor tosuccess, along with consistency within the team.Drilling engineers and other crew members havebeen dedicated to the project for long periods oftime, enabling them to share and build expertiseand learn from experience.

Schlumberger drilling engineering experts haveprovided 24/7 support for operations, from devel-oping initial well plans to preparing post-projectreports. These experts were both local – i.e., Okla-homa City, Okla., and Midland, Texas – and aroundthe world. All team members have been able toshare data through the InterACT secure connectiv-

ity, collaboration, and information system irrespective oftheir location.

Dedicated operations support has helped to drive con-tinuous improvement in drilling efficiency throughimproved processes and identifying the most fit-for-pur-pose technology. Several benefits have been realizedthrough changes to bottomhole assembly components,such as identifying drill bits that are more resistant toabrasion in this particular geological environment.

Bed boundary mapper azimuthal measurements, combined with the use of an RSS in the lateral, haveenabled wells to be placed accurately within thin targetsand layers that differ significantly from prognoses. Todate, more than 97% in-zone has been achieved from alllaterals drilled, with no sidetracks required.

Growing experience in the Bone Spring area has led tothe identification of an optimized drilling target windowwithin some sand units. Drilling within this windowhelped mitigate high shock and vibration to the toolstring, allowing the operator to optimize drilling mechan-ics and improve drilling ROP, maximizing efficiency.

Prior to deploying RSSs and bed boundary mappingtechnology, wells could take more than 70 days from spudto rig release. Using the technology to steer in-zone, thisquickly dropped to around 51 days and has continued toimprove. Best composite time targets have been chal-lenged and reduced forsubsequent wells. Thelatest record for spud torig release of a well was24.25 days.


DIRECTIONALDRILLING

Boundary detection based on azimuthal resistivity curves was used to

generate the boundary mapping PeriScope inversion canvas with RTGS.

Note the flat resistivity and gamma ray response across the target inter-

val and also the difference between planned and drilled trajectories.

EPmag.comREAD MORE ONLINE

There is more to the story…



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Society of Exploration Geophysicists International Exposition and 81st Annual MeetingHenry B. Gonzalez Convention Center • 18-23 September 2011 • San Antonio, Texas USA

Photo courtesy of Stuart Dee,SACVS

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91


SUBSEATECHNOLOGY

Gas in the riser presents a significant challenge to con-ventional deepwater drilling operations. Once above

the subsea BOP, a gas influx is an immediate and poten-tially uncontrollable threat to personnel, the environ-ment, the rig, and even the well.

For this reason, the first indication of a gas influx on adeepwater well usually initiates an expensive, time-con-suming mitigation process that typically involves weight-ing-up the mud system and implementing BOPprocedures.

This best-practice well-control response commonly isundertaken with imprecise information about the natureof the kick because it is driven by an urgent need to stopthe influx and prevent the gas from rising in the well bore.And the step is not without its own risk. In a narrow drilling

window, heavier fluid can reverse the balance from mitigat-ing the kick to initiating a loss. Cycles of kicks and lossesare a common yet costly problem. If these measures areapplied in the reservoir section, heavier mud also canincrease skin damage and impair potential production.

To break this reactive well-control dilemma and signifi-cantly reduce the risk posed by riser gas, managed pres-sure drilling (MPD) methods are being used to preciselymeasure and manage small downhole pressure fluctua-tions before they become a well-control event. Central tothis capability is the growing sophistication of rotatingcontrol device (RCD) technology designed specifically forthe unique challenges of riser applications.

Riser integrationThe latest advance in MPD riser technology is the indus-try’s first RCD to be integrated with the riser below thewater line. It also is the first RCD to conform to API16RCD drill-through specifications.

Installed for the first time on a drillship in Indonesia,the MPD system successfully provided early kick detectionin difficult carbonate formations where kick-loss problemsare common. Gas influxes were detected at volumes of

only a couple of barrels, and well pressurewas managed while drilling, making con-nections, and tripping. In addition, theMPD system acquired formation pressuresin real time and allowed logs to be run in asafe, controlled manner.

Drilling methods were transitioned easilyto apply the most appropriate approach tospecific wellbore conditions. The upperpart of the carbonate section was drilledusing constant bottomhole pressure (BHP)MPD methods to manage pressures withina narrow drilling window. When the win-dow closed and losses to natural fracturesbecame total, a shift was made to pressur-ized mud cap MPD.

To create an MPD system aboard thedrillship, a Model 7875 below-tension-ringSeaShield RCD was installed in the MPDriser joint on the top of the upper annularpreventer approximately 140 ft (43 m)

below the sea level surface. It is not the first time MPD operations have been imple-

mented aboard a floating structure, but all previous RCDinstallations have been above the water line and tensionring. The first MPD application from a floater was per-

Managing the threat of riser gasMPD advances are taming an old adversary

by measuring and managing downhole gas influxes.

Andrew Barry, Weatherford International Ltd.

The Model 7875 below-tension-ring RCD was installed on a deepwater well offshore

Indonesia so the operator could fully enclose the well bore and all drilling fluids in a

closed loop and employ advanced drilling techniques without compromising the

rig’s heave compensation. (Images courtesy of Weatherford International Ltd.)

72-73 Subsea-weatherford_72-73 Subsea-weatherford 3/23/11 4:59 PM Page 72


SUBSEATECHNOLOGY

formed by Weatherford InternationalLtd. in 2004 using a Model 7100 RCDdesigned for surface applications.

The integration of the RCD with theriser is a significant advance in RCD technology.

Because it is made up below the ten-sion ring, no modifications are requiredto the riser’s telescoping slip joint or therig’s mud returns system. With the systemin place, drilling operations can shift eas-ily between either conventional or MPDdrilling methods.

Many design changes were made toaddress riser applications. Location is keyto these changes. While surface RCDdesigns sit atop the BOP and thus requireonly a bottom flange to bolt them to thestack, integration with the riser requiresthe RCD to be connected at the bottomand the top. Location also creates chal-lenges for installing, maintaining, andoperating the RCD far below the rig floorwhere conditions make it dangerous anddifficult to deploy personnel.

The riser RCD addresses this issue with a number ofinnovations. Among them, the system has a hydrauliclatching system for changing bearing and sealing elementswithout the need for personnel in the moonpool area. Abearing assembly running tool and ancillary equipmentfacilitate rig floor positioning and removal. A subsea-ratedhydraulic stab plate is used to make hydraulic and electri-cal connections below the water line, and the multiportconnections speed the deployment and makeup ofhydraulic and electrical lines and eliminate multiple con-trol cables.

Managing micro-fluxesMeasuring and managing downhole pressure fluctuationsare core capabilities of MPD methodologies. In a closed-loop MPD circulating system, micro-fluxes in BHP areidentified immediately in small increments. Conversely, alittle annular pressure applied at the surface is conveyedrapidly to the bottom of the hole, changing equivalent cir-culating density without altering the mud system.

This takes place with the rig’s BOP and mud manage-ment systems in place and ready to take over should a well-control event occur. MPD operations are not a replace-ment for well-control methods. Rather, they provide anearly warning and management capability that stands infront of traditional well-control methods to reduce their

use and better inform their application. In doing so, MPD reduces the threat

posed by riser gas in several ways. It pro-vides a highly sensitive instrument foridentifying an influx and the means tomanage it. This greatly reduces the risk ofan influx escalating into a well-controlevent. If necessary, the gas influx can bemanaged, circulated out of the holethrough the riser and flow spool, anddiverted away from the rig floor.

Even when drilling conventionally, theriser-gas handling capabilities of the sys-tem remain functional. Should gas enterthe riser, circulation is stopped, and thesurface and subsea annular BOPs areclosed to contain the gas in the riser.Either the MPD or rig manifold can beused to circulate the gas out in a con-trolled manner. And should an eventoccur that calls for well control, MPDmeasurements enable a much moreinformed and timely decision.

RCD basicsThe defining MPD technology is the RCD. Its ability tocontain and direct annular fluids and gas is what createsthe closed-loop circulating system that is the basis for MPDmethodologies. The device’s development path spansdecades and a scope of applications from basic land opera-tions to drillships and marine risers.

Those pioneering efforts ultimately evolved into themature set of MPD methodologies being used for offshoreexploration and development drilling.

These systems employ a set of tools that includes RCDs,flow metering technologies, drilling choke manifolds, anddownhole isolation valves. The MPD components are inte-grated by software that monitors, analyzes, and manageswellbore pressure. A key aspect of this MPD advance hasbeen the growing sophistication of the RCD. The chal-lenges of deepwater drilling have resulted in the nextmajor evolution of RCD design and MPD application.

The most recent advance integrates the RCD in the risersystem. By eliminating modifications to the rig system orinterference with conventional operations, the new below-tension-ring riser RCDaddresses many deepwaterissues, including the safety,environmental, and opera-tional challenges presented byriser gas.

If a gas influx ascends above the BOP

and enters the riser, the SeaShield

marine series, including the Model

7875 below-tension-ring RCD, enables

the operator to contain and bleed off

the gas, minimizing potential risks.



72-73 Subsea-weatherford_72-73 Subsea-weatherford 3/23/11 4:59 PM Page 73

R isers and flowlines are integral components of subseadevelopments. The design of these components

requires extensive analysis that involves taking intoaccount a complex set of interacting gravity and hydro-static and dynamic effects in addition to considerationsregarding the response of the materials of these compo-nents and their interaction with the seafloor. The use ofnumerical, in particular finite element (FE)-based analysistools, in designing these components is essential.

PIP flowlines, SCRsDesigning pipe-in-pipe (PIP) flowlines and steel catenaryrisers (SCRs) requires engineers to consider effects suchas the interaction between unbonded nested pipes andassessing necessary pretension of the inner pipe to allevi-ate adverse effects of locked-in compression after pipelayis complete.

Interaction between inner (carrier) and outer (jacket)pipes of an unbonded PIP flowline or SCR is complex andrequires specifying axial (e.g., friction characteristics) andradial (e.g., relative movement) contact characterization.This is modeled in Abaqus using the ITT elements. Mod-eling the contact between the inner and outer sets ofpipes introduces a great level of nonlinearity to the modeland adds computational cost. However, FE analysis thatuses such advanced techniques is essential to assessingrequired pretension of the inner pipe so that the finallocked-in compressive stresses are acceptable.

Pipelines for the ArcticDesigning pipelines and risers for arctic conditions intro-duces challenges, such as ice-loading modeling, ice-goug-ing and/or permafrost thawing, and frost heave. Severalcodes have been developed during the last two decadesthat have addressed ice modeling and loading, includingAPI RP 2N, IEC and, most recently, ISO/DIS 19906. Thesecodes provide ice static and dynamic loading characteriza-tion on common structural shapes and sizes.

Ice-loading modeling in numerical schemes (e.g., FE) hasdeveloped over the years, yet it still encounters challenges.Different material models have been shown to suit various

applications, depending on the type of iceunder consideration, size of the loadedarea, and expected level of stress and rateof loading. For example, elasticity has beenadequate for solid/consolidated ice underlow levels of stresses and relatively rapidloading, unconsolidated ice under higherlevels of stress can be better modeled as aplastic material, low loading causes ice tobehave in a viscous manner, and damagedelasticity has been successful in describinginternal damage of the ice due to brittlecracking.

Ice gouging is a natural phenomenon during which alarge floating ice mass gouges the seabed, threatening theintegrity of subsea structures and pipelines. Modeling theimpact of the phenomenon on these structures is challeng-ing as it involves a number of complex interactions, namelybetween the aero- and hydrodynamic forces and ice mass,between the ice mass and seabed, and between the seabedand subsea structures. Analysis tools based on state-of-the-art 3-D continuum FE, which ensures highest accuracy inthe simulation, have proven critical to accurate and realis-tic pipeline assessment subject to such events.

A pipeline buried in the permafrost can be subject tooverstress if the pipeline degrades the integrity of the per-mafrost by warming and thawing it. Depending on proper-ties of the frozen soil, thawed permafrost could collapseand subject the pipeline to excessive deflection and strains.Simulating this process and the impact on the pipelineinvolves multiple physical processes, including heat trans-fer, soil consolidation, and soil-pipeline interaction.

Dynamic design tools increase safetyAdvanced finite element analysis tools facilitate offshore risers and flowlines design,

help operators anticipate the effects of any dynamic scenario, and prepare for it in the design phase.

Ayman Eltaher, Wood Group, MCS Kenny

Analysis tools based on state-of-the-art 3-D continuum FE, which ensures highest accuracy

in the simulation, have proven critical to accurate and realistic pipeline assessment sub-

ject to such events. (Images courtesy of Wood Group, MCS Kenny)


SUBSEATECHNOLOGY

74-76 Subsea-Wood_74-76 Subsea-Wood 3/23/11 4:59 PM Page 74


Pipelines for HP/HT conditionsDesigning a pipeline for HP/HT conditions shouldaccount for thermal expansion and degradation of mate-rial properties because of elevated temperature as well aspossible upheaval and/or lateral buckling due to bothhigh temperature and high pressure. The concept ofeffective forces and true stresses should be clear andaddressed correctly. Also, accounting for the behavior ofthe inner and outer pipes of a PIP configuration usuallynecessitates modeling the two pipes and complex interac-tion between them. Interaction between the pipeline andseabed also should be accounted for, particularly the soilresistance to pipeline movement and resulting buildup ofcompressive forces.

Pipeline-soil interaction is one of the more complex andless established aspects of the process; a number of jointindustry projects (JIPs) have addressed the issue. User-defined subroutines have been used to implement recom-mendations of these JIPs to model the pipeline-soilinteraction in both upheaval and lateral buckling as wellas potential axial movement (e.g., walking).

Components of pipelines, risersBesides pipes, pipelines and risers incorporate a numberof components that work as connecting points betweendifferent parts of the pipeline/riser system and at theboundaries of the system. Components include flanges,bulkheads, load-shares, tapered stress joints, flex joints,and bend stiffeners. These usually are complex and caninvolve parts connected loosely, by way of bolts, and canmove relative to one another. This makes the analysis par-ticularly involved and requires numerical simulation ofnonlinear behaviors, such as contact between surfaces,friction and sliding, and bolted connections. Analyzing

such components using FE analysis requires advancedtechniques of solid modeling, nonlinear material model-ing, and contact, which usually entails significant degreesof nonlinearity and demand for computational power andproper engineering judgment.

JumpersDesigning jumpers requires considering numerous staticand dynamic effects. Static and quasi-static loads includegravity, current, and waves; dynamic loads include flow-induced vibration (FIV) and vortex-induced vibration(VIV). VIV for simple-shaped jumpers usually is analyzedusing code-based equations, whereas VIV of complex-shaped (e.g., multiplanar) jumpers and FIV normallyrequire numerical analysis such as computational fluiddynamic (CFD), which simulates induced turbulent flowand vortices and resulting vibration of the jumper.

Pipeline, SCR seabed interactionProper modeling of the SCR touchdown zone (TDZ) isessential to realistic assessment of the fatigue life of thatstructure. However, the SCR TDZ modeling also is chal-lenging, as it requires modeling the highly complexresponse of the soft seabed and potential forming of atrench in the seabed over time.

A number of simplified models have been developed forimplementation in global SCR analysis; however, thesemodels usually are limited to specific ranges of soil typesand SCR pipe parameters. Currently, new FE techniques(such as coupled Eulerian Lagrangian, or CEL, FE analy-sis) are used to model the response of the SCR when inter-acting with the seabed for better understanding of thatinteraction and then simplifying it for global analysis ofthe SCR.

MCS Kenny has developed CEL models to simulatepipeline interaction with the seabed, including the impactof mud flow on pipeline and the response of pipeline tolateral and upheaval buckling.

CEL models simulate pipeline interaction with the seabed,

including the impact of mud flow on pipeline and the response

of pipeline to lateral and upheaval buckling.

SUBSEATECHNOLOGY

VIV of complex-shaped (e.g.,

multiplanar) jumpers and FIV

normally require numerical

analysis such as CFD.



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Extreme water depths and low reservoir pressures of the Perdido development in the Gulf of Mexico

(GoM) were particularly challenging for the engineer-ing teams faced with tying multiple subsea completionsand lifting the production stream 8,000 ft (2,439 m)from the seafloor to the production facility. It was obvi-ous that natural formation pressure was insufficient todeliver the production liquids to the surfaceand that some form of artificial lift would berequired.

According to Dusty Gilyard, senior comple-tions engineer at Shell, who has been workingon Perdido since the project’s inception, Shellconsidered several types of artificial lift, butultimately decided electrical submersiblepumping (ESP) systems were the best proventechnology with a track record of reliableoperations.

“Shell looked at two major suppliers,”Gilyard said. “Baker Hughes was selectedbecause it had a proven track record withcapable technology and the best system tosupport it.”

In January 2006, Shell awarded BakerHughes Inc. contracts for seabed productionboosting systems at two deepwater subsea proj-ects: BC-10 offshore Brazil and Perdido in theGoM. Perdido is the first development in theGoM to use ESP systems in seabed verticalbooster stations.

Unique, purpose-built ESP systems designedESP booster systems offer several advantagesover alternative methods, including deploy-ment from vessels of opportunity, redundantdesigns to maximize run time, and configura-tions that use existing infrastructure to housethe ESP systems. These features provide oper-

ators economic solutions to maximize production fromsubsea fields.

Shell contracted Baker Hughes to provide five Cen-trilift XP enhanced-run-life ESP systems as well as engi-neering design, qualification, and testing services. Eachsystem installation included a liquid/gas separator tomaximize ESP system performance. The vertical boosterstations were designed to handle production from threesubsea satellite fields tied back to the Perdido spar hostfacility.


Deepwater production technology gets a boost

Facing technical challenges akin to the first moon landing, Shell attacked a low-pressure reservoir in 8,000 ft water depth.

Jeff Knight and Ryan Semple, Baker Hughes Inc.

SUBSEATECHNOLOGY

The Perdido spar, in approximately

8,000 ft (2,439 m) water depth in

Alaminos Canyon Block 857, is the

GoM’s deepest water production

facility. (Image courtesy of Shell)

77-82 Subsea-BakerHughes_77-82 Subsea-BakerHughes 3/23/11 4:59 PM Page 77


The 1,600-hp ESP systems wereto be installed in five 350-ft (107-m) long caissons connecteddirectly to the platform’s top-tensioned production risers.Three have been installed, andthe remaining two will be in placeby the end of 2011. The caissonslie directly beneath the spar pro-duction facility. Each caisson isequipped with cylindrical-cyclonicgas separation systems to separatenatural gas entrained in the fluidsbefore the fluids enter the ESPsystem.

Each pumping system candeliver between 10,000 and 30,000b/d of liquid. For this application,the pumps were designed forapproximately 20,000 b/d. If allfive systems run at nominal flowrate, the platform can deliverabout 100,000 b/d of production.The ESP systems also control thespar riser head pressures.

“In the case of Perdido, the wellswould not naturally flow to sur-face, so we needed something thatwould handle the boost and wasextremely reliable,” Gilyard said.“We plan to pump 100,000 b/d ofoil, and unless all five pumps areworking, we’re not going to makeour goal. We needed the caissonon the ocean floor so the wellscould flow to it and we couldpump the fluid to surface.”

Design pushes the limitsBefore installation on Perdido, adjustments to the sys-tems were necessary to meet the requirements of thedeepwater development. Both Shell and Baker Hughesconducted extensive research to design ESP systems forthis application.

Early in the project, Baker Hughes was involved inpre-engineering for this unique application. The ESPsystem design had to take into account all of the possi-ble pumping scenarios at Perdido. Much of the applica-tion engineering work was done to ensure the bestpossible design to match the required operating condi-tions. Technology planning considered varying potential

operating conditions such asrequired boost pressures andflow rates – all while consider-ing a multitude of fluid com-positions since productionfluids from each well wouldbe commingled at the ESPsystems.

More than 200 scenarioswere modeled to determinethe system that would workbest in the application.Shell’s front-end engineeringrequirements included thor-ough qualification testing ofthe new designs. Because ofthe unique challenges of thisinstallation, the companiesworked together to definethe expected demands on the ESP systems while alsoreviewing the run life and history of the technology.Design details were validatedon components as specific asthe type of elastomer used on a seal.

“The most critical aspectwas the functionality of theESP system,” Gilyard said. “Itneeded to work in any type ofenvironment.

“The ESP was put in a subsea separator system and tested for operabilityusing different monitoringfunctions and level controlmethods. We consideredcombinations of multiple

temperature and flow rates. The pump had to be able to work both mechanically and electronically withoutany gauge interference.”

Some enhancements were developed to meet the runlife expectations of the project. One of these was chang-ing the configurations of the seal section to include anextra chamber. A standard seal configuration for thissize of equipment has two chambers, but a third wasadded for redundancy. Two seal sections were run intandem, providing six chambers.

Another new technology development was the thrustbearing in the seal. Based on the application review, it

SUBSEATECHNOLOGY

Inside the caissons are 1,600-hp Centrilift XP ESP sys-

tems that boost produced fluid from the seabed to the

spar. (Illustration courtesy of Baker Hughes Inc.)



was determined that the existing highest capacity thrustbearing in the seal was insufficient in some pumpingconditions. A new enhanced high-load thrust bearingwas designed and qualified to account for maximumpump thrust.

Installation hurdles resolved The engineering team also designed specialized installa-tion equipment to meet Shell’s requirements, includingnew tooling to meet the lifting and hoisting standards.New equipment baskets, lifting subs, and control linepush arms were created as well.

Baker Hughes’ intelligent production systems (IPS)group designed new equipment for the project as well,including special spooling units that deployed the heavyarmored power cable that supplies electricity to the ESPmotors. Normally, 8,500 ft (2,591 m) of cable would besupplied on two reels and spliced together during instal-lation. Shell specified that the ESP cable needed to beon one large reel to avoid switching the reel on the plat-

form. With the help of the IPS group, a heavy-dutyspooling unit that could advance and take up the cableas it was run was developed along with transportationframes that could store extra cable or an empty reel.

The project continuesBaker Hughes continues to contribute to the success of Perdido. By year-end, all of the ESP systems will beinstalled in the five vertical subsea boosting stations.This will be a long-term relationship as the projectswitches from installing to sustaining to ensure reliableoperation of the production systems. Over time, as pro-duction increases, the two companies will collaborate tomaximize the performance of the systems and optimizeproduction.

The project was an important learning experience for everyone involved. The technology developed forPerdido and BC-10, along with the lessons learned fromworking together as a cohesive team, have advanced sub-sea development capabilities for the entire industry.

For more Subsea Technology

articles, visit

EPmag.com


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Shale oil drilling is picking up in the Williston Basin’sBakken shale, one of the hottest oil plays in North

America. The Bakken, which extends through North Dakota

and eastern Montana in the US and into Saskatchewanand southwestern Manitoba in Canada, produced225,000 b/d of oil in 2010, up from 3,000 b/d in 2005,according to the Energy Information Administration(EIA). Current EIA predictions indicate the Bakkencould produce 350,000 b/d of oil by 2035. Most analyststhink that estimate is too low.

Scott Sheffield, head of Pioneer Natural ResourcesCo., estimates new technology will allow the US to pro-duce an additional 2 MMbbl/d of oil from the Bakkenand other shale oil plays. “It’s going to have a majorimpact on the United States reducing imports,”Sheffield said at IHS CERA’s CERAWeek in March 2011in Houston.

Guy Caruso, former head of the EIA and currently anadvisor at the Center for Strategic and InternationalStudies, agrees. “If we get 2 MMbbl/d, that could have amajor impact on world oil prices,” he told CERAWeekdelegates.

Increasing Bakken activityOver the last five years, leasing in the Bakken hasincreased significantly, and bonus payments per acrealso have gone up. According to the US Department of Energy’s National Energy Technology Laboratory(NETL), total lease payments exceeded US $100 million in 2009.

In 2008, the US Geological Survey estimated the USportion of the Bakken formation contains between 3and 4.3 Bbbl (a mean of 3.63 Bbbl) of undiscovered,recoverable oil. The number of producing wells and thevolume of oil production have grown with leasing anddrilling growth. According to the NETL, Bakken pro-duction has reached approximately 8 MMbbl per monthfrom nearly 4,500 producing wells.

The Elm Coulee field in Richland County, Mont., is one

of the Bakken’s significant emerging fields. Discovered byLyco Energy in 2000, the field has produced more than41 MMbbl of oil and 24 Bcf of gas from more than 400horizontal wells. It has relatively low porosity (8% to 10%)and an average of 0.05 md permeability, with natural frac-turing likely contributing to production.

The reservoir has been developed over an area of 450sq miles (1,165 sq km), targeting the middle member ofthe Bakken formation on 640- and 1,280-acre spacing.Recovery per well is 350,000 to 600,000 bbl, and ulti-mate recovery for the field is greater than 200 MMbbl.

The Parshall field, which also produces from the Mid-

BAKKEN SHALEBasin & Location Information

Basin Williston

Location US: North Dakota, MontanaCanada: Saskatchewan, Manitoba

Est. basin area 200,000 sq miles (520,000 sq km)

Reservoir Characteristics

Depth 8,500 to 10,500 ft (2,591 to 3,200 m)

Net thickness 140 ft (43 m)

Total organic carbon (TOC), %Ro 6 to 20

Total porosity (%) 5

Economic Data

Original oil-in-place (MMbbl) 5

Gross EUR (Bcfe) 5.1

Gross well cost (USD) $5.5 million

Net EUR (Mboe) 697

2009 production 55.2 MMboe

Oil gravity 42%

Permeability 0.005 to 2 md

EUR 0.5 MMbbl

Source: UGcenter.comUpdated 10/04/2010

UNCONVENTIONAL:BAKKEN

Ashley E. Organ, Associate Editor; and Richard Mason, Executive Editor, Online

Bakken activity on the riseNew technologies are increasing recovery, and operators are moving

to delineate areas outside the core Bakken region.

83EPmag.com | April 2011

83-91 Uncon-Bakken_83-91 Uncon-Bakken 3/23/11 5:00 PM Page 83



The Williston Basin is host for the Bakken play –

the hottest oil play in the US. (Map courtesy of

Hart Energy)



It's about national strenlocal leadership.

A R K - L A - T E X I A P P A L A C H I A N I MID CONTINENT I P E R M I A N B A S I N I ROCKY MOUNTAINS I GULF COAST

With extensive knowledge of thelocal regions in which we work,Basic provides a range ofpressure

pumping services, includingWell Servicing • Contract Drilling fracturing, acidizing, cementing,

• Fluid Services • Wireline coiled tubing and nitrogen service,• Pumping Services • Snubbing Services to improve production and• Rental / Fishing Tools • Well Site Construction maximize our clients' investment.

O U R L I F E ' S W O R K I S T H E L I F E O F T H E W E L L . TM BASICw

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dle Bakken, was discovered in 2006 on the east side ofthe Nessen Anticline. As of April 2010, the field had pro-duced approximately 32 MMbbl of oil and 13 Bcf of gasfrom 228 wells.

According to the NETL, the top 20 players in the

Bakken hold nearly 5.5 million acres of prime acreage,with the top three controlling more than two millionacres. Continental Resources, the top driller and lease-holder in the play, has 864,559 net acres. Whiting Oil &Gas Corp. has 14 rigs operating in the Bakken andapproximately 480,000 net undeveloped acres in theBakken/Three Forks. EOG Resources Inc. has 11 rigsoperating and 580,000 net acres.

Developing new technologiesThe Bakken is a relatively young play, but companiesworking in the area already have helped to make animpact through new technologies.

In 2009, Continental Resources performed the first24-hour continuous frac in the North Dakota portion ofthe play. In 2010, the company developed the ECO-Paddrilling concept, a system where multiple horizontalwells are drilled from a single pad with zero boundary-line setbacks. The concept can reduce drilling and com-pletion costs per well by approximately 10%, withapproximately 70% less surface footprint area than fourconventional drilling pads and one access road.

Smith Bits has designed the Spear shale-optimizedsteel-body PDC bit, which can drill a curve and long lat-eral hole section for faster penetration rates in lowhydraulic energy environments, reducing the number oftrips downhole and the associated rig time. According tothe company, the bit also reduces nonproductive timeby minimizing vibration and preventing packed blades,plugged nozzles, and cutter damage. It permits highROP through a combination of tall and thin blades,which provide a large area for cuttings flow. Thehydraulic design directs flow toward the cutter faces,keeping them sharp while sweeping cuttings away from



Results from simultaneous fracture stimulations on three wells in

Montana demonstrate the potential benefits of these enormous

operations, but the logistics are daunting. (Photo courtesy of BJ

Services Co.)

The North Dakota Industrial Commission is projecting another

30 rigs will enter the Williston Basin in 2011 on top of the 170

already in the play. If true, those numbers amount to an 18%

increase and imply an aggregate industry capital program of

US $13 billion on the basis of 2,000 projected wells. (Source:

“Four Bakken Themes for 2011” by Richard Mason, courtesy of

UGcenter.com)

Bakken Rig Employment Plans, 2011

Company Current rigs Projected 2011 Change

Continental 23 25 2

Hess 11 18 7

Brigham 7 12 5

Occidental 7 12 5

Oasis 6 7 1

Enerplus 2 5 3

Denbury 2 3 1

QEP 2 3 1

Kodiak 2 3 1

Totals 64 90 26

The top 10 Bakken acreage holders

cover 51% of the play’s geographic

footprint. (Source: Hart Energy)

Top Bakken Acreage Holders

Company Acreage

Continental 864,559

Hess 750,000

EOG 600,000

Whiting 552,127

ExxonMobil 450,000

Marathon 391,000

Brigham 365,000

Oasis 303,000

Denbury 275,000

Newfield 271,000



X/ i

IT'S ALMOST MIDNIGHT.DO YOU KNOW WHAT YOUR

COMPRESSOR IS DOING?

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the bottom of the hole and around the bullet-shapedbody into the annulus.

A more recent milestone occurred in March 2011, whenBaker Hughes Inc. installed a 40-stage openhole comple-tion system in the Williston Basin, the largest number ofstages ever performed in a single lateral frac sleeve/packer completion system. The company’s FracPoint EX-C multistage fracturing system was deployed in WhitingPetroleum Corp.’s Smith 14 29XH horizontal well.

“The industry continues to push the limits of total fracstages in horizontal completions in the Bakken shaleand other unconventional reservoirs,” said Paul Butero,president of the US Land region for Baker Hughes.

Reactive element packers allow for a wide range ofopenhole sizes and improve the capabilities of packerand sleeve completions. In many areas of the WillistonBasin, Baker Hughes’ REPackers are used in the Frac-Point EX-C system to isolate intervals of a horizontal sec-tion, while frac sleeves are used to deliver the fracturetreatment. The system extends current capabilities to 40stages via 1⁄16-in. incremental changes in ball size toincrease the number of ball seats and provides addi-tional mechanical support to the ball during pumpingoperations.

R&D is keyDeveloping new technologies specific to the area is a priority. The National Energy Technology Laboratory(NETL) has funded a number of R&D projects to improverecovery, decrease the operating footprint, and enhancesafe and environmentally responsible shale oil develop-ment. The lab plans to develop and/or refine several keytechnologies to exploit the Bakken’s full potential.

Further deployment of microseismic fracture monitor-ing will provide a greater understanding of fracture prop-agation and extent in the Bakken system, resulting inbetter frac jobs and enhanced production. MicroSeismicInc. already has buried seismic arrays across more than150 sq miles (388 sq km) in Mountrail County, N.D.,using more than 1,200 geophone channels to monitor,map, and analyze hydraulic fracturing operations.

Extended-reach and rotary steerable drilling also arekey to developing the Bakken. Without extended later-als and multistage hydraulic fracturing techniques,Bakken development would be uneconomical. With lat-erals now extending beyond 10,000 ft (3,048 m), precisewell placement control is crucial, as is the ability todeliver a smooth well bore to enable single-trip fractur-ing and completion equipment installation.

The NETL also is investing in enhanced multistagefracturing to increase the ability to pump larger multi-

stage fracs to improve economics. And projects in theworks will target water use as well. Typical water use forhydraulic fracturing in the Bakken is 1.5 to 4 million galper well. Surface water in the Williston Basin is in shortsupply, and costs associated with acquiring frac waterand disposing of flowback and produced water canrange from $2 to $11.75/bbl.

The NETL continues to fund R&D projects that willlead to more efficient oil recovery and improved envi-ronmental impact.

Additional M&A likelyBy Richard Mason, Executive Editor, Online

After the US $3.6 billion acquisition flurry thatcharacterized 4Q 2010, the Bakken still remains

a candidate for additional mergers and acquisitions(M&A). Recent deals include Hess Corp., whichincreased its holdings to 750,000 net acres follow-ing the $385 million acquisition of American Oil andGas Inc. in July 2010, and the $1.1 billion acquisitionof Tracker Minerals in December 2010. Also, Occi-dental Petroleum Corp. picked up Anschutz Corp.’sBakken acreage for $1.4 billion in December 2010,while Williams Cos. entered the play with the $925million purchase of Dakota-3 E&P in the samemonth.

Other recent acquisitions include Kodiak Oil andGas, which acquired acreage for $110 million froman undisclosed seller, and Oasis Petroleum, whichpicked up acreage in Montana and North Dakota intwo separate transactions totaling $78 million.

In all, there were more than three dozen acquisi-tions in 2010, and deal-making should continue at arespectable pace in 2011 as private operatorsremain open to an exit strategy after acquiringacreage and proving up planned development unitpotentials or existing players look for bolt-on acqui-sitions in neighboring parcels.

While the number of public operators willing topay $1 billion for Bakken acreage is limited to allbut the largest oil and gas operators, independentssuch as Brigham Exploration Co. face daunting cap-ital requirements to fully exploit holdings and fre-quently prove attractive for larger companies withlarge-scale project management skills – the perfectcandidates to pursue Bakken acquisitions as full-scale resource development gets under way.


88 April 2011 | EPmag.com



It 's the Little Things.Let btatUon name au of your naKKen weusite aetaus, so your crew can

1 spend its ti i ;i n fs h = t matter most.

Accommodations . Solids control . Construction and communications services . Lots of little things onthe wellsite can distract your crew and take the focus away from the well itself-and the bi g picture.

Stallion Oilfield Services takes care of all these tertiary services , including:

Onshore Workforce Accommodations Remote CommunicationsSurface Rental Equipment Solids ControlWellsite Construction Drilling Support

In the Bakken and beyond , when you want to sleep better knowingStallion Oilfie ld Services wil'. handle the details of your next well,call Corporate Sales at (713) 528-5544.

www.staywettf ocused.co H7M

83-91 Uncon-Bakken_83-91 Uncon-Bakken 3/23/11 5:00 PM Page 90 83-91 Uncon-Bakken_83-91 Uncon-Bakken 3/23/11 5:00 PM

Eagle Ford Update • Global Shales • NGLs • Permian Basin • 2011 ForecastsDEVELOP INGUNCONVENTIONALGAS

6th Annual Conference and ExhibitionApril 18-20, 2011 • Fort Worth Convention Center • Fort Worth , Texas

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ChesapeakeE N E R G Y

Weatherford'

NEWPARKDRILLING FLUIDS

Sponsored by:

HALLIBURTON

p II NETN ERLAND , SEWELL0. ASS OCIATES, INC.

Tripoint LLC

TUDORPICKLRING SELECTHOLT&CO eA ENERGY SERVICES

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BAKERENC,u INVes TmrrNT S L.P. HUGHES

U. S. SteelTubular Products Tenaris

LEXPRO

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: EIGGLOBAL ENERGY PARTN ERS

Stalliona ? TGS ?

drilling fire r e °

BASICOBENERGY SE R V I C E S

Keynote Speakers Include:

Richard K . StoneburnerPresident and COOPetrohawk Energy

Bobby TudorChairman and CEO

Tudor. Pickering , Holt & Co. LLC

Statoil

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PETROHAWKENERGY CORPOR477ON

SUPERIOR

GE Oil & Gas HollandSERVICES

GeoGraphix

Macquarie Tnstone

Clariant Oil Services

Olivier LazareVice President . New Business Development

Shell Exploration & Production

SchlumbergerNATIONAL OILWELL VARCO

M Cordillera

Clariant

stFiCo

MAGNUM

O I L - T O O L SI" L. U A I G RA L

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MicroSeismic

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TEXAS CAPITAL BANK- press

Presented by:

LG

Investor

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CASE HOLE

,L IONS

When conventional, manually operated riser-han-dling tools appeared incapable of fully supporting

a particular drilling riser system, it was time to go backto the drawing board.

In response to a client’s need, Claxton EngineeringServices Ltd. initiated an intense in-house developmentprogram to create an innovative hydraulic tool. Theresulting design eliminates the need for scaffolding and manual handling and offers protection to the very expensive associated riser connector. It also can cut rig time and costs.

Need for innovationThe limitations of the conventional heavy-duty seg-mented handling tool became apparent on this projectwhen it could not hold the required internal pressurewhen attaching to the 18¾-in., 49-ft (15-m) NT-2 tensionjoint. After exhausting all of the options, includingchanging the construction material and altering the seg-ment design, engineers concluded that the client’srequirements could not be met with the existing design.A new approach clearly was needed.

The engineering team set about re-engineering theconventional riser-handling tool.

Over the course of the ensuing10 months, they designed,

manufactured, and tested anew multipurpose,hydraulically actuated run-

ning tool through aprocess that

involved

internal and client design reviews and third-partyapproval. Manufacturing and mechanical completionactivities were in accordance with the Norwegian petro-leum industry’s NORSOK standards.

This tool not only met the needs of the immediateapplication, but it also overcame the shortcomings ofthe manually operated variant. For one thing, the con-ventional tool requires the erection of scaffolding toreach the NT-2 joint. This adds time to the operationand introduces safety risks from the potential fordropped objects. Another shortcoming of the manualtool is that operating the tool is time-consuming becauseeach of the 12 segments has to be manually securedonto the tool’s housing using a threaded stud and nut,which are tightened using a standard torque package.

Incorporating hydraulics into riser handlingIn contrast, the new tool’s hydraulic operation meansriser handling can be much quicker. Scaffolding doesnot need to be erected, and the tool hydraulically locksitself onto the NT-2 joint in seconds. A crucial step for-ward in terms of safety is that because the tool ishydraulically actuated, it can be operated remotely bymeans of a dedicated combined hydraulic power unitand reel, which reduces the risk of harm to personnel.

In its first real-world application, a Norwegian drillingoperator used the tool to run and remotely pressure-testthree 6,019-psi (415-bar) full riser systems. The tool cut4.5 hours of rig time from each run and decreased theproject costs by US $2.9 million.

The tool now is available as part of Claxton’s strategyof continuing improvements in efficiency and safety.The tool’s key features include its ability to:

• Perform a wellbore pressure test to 7,000 psi whileholding the tension at 308 metric tons (flanged andquick-connect systems are available to 12,200 psi);

• Act as a contingency method for applying 400 metrictons of tension to the drilling risersystem before BOP installation (withno internal bore pressure);• Interface with either a Grayloc

192 or 196 gasket seal profiled,

New tool makes riser handling faster and safer

An innovative hydraulic riser-handling tool provides a means of fully supporting a drilling riser system during installation and recovery.

Blair McKnight, Claxton Engineering Services Ltd.

Claxton’s innovative hydraulic riser-handling

tool provides a means of fully supporting a drilling

riser system during installation and recovery.

(Images courtesy of Claxton Engineering Services Ltd.)


RISERTECHNOLOGY

92-93 Riser-Claxton_92-93 Riser-Claxton 3/23/11 5:00 PM


RISERTECHNOLOGY

93

18¾-in., 49-ft NT-2 pin by means of a removable adap-tor housing the seal elements; and

• Lift a drilling riser tension joint weighing up to 20metric tons and measuring up to approximately 39 ft(12 m).

The tool’s vital safety features include visual indicatorrods that show whether the tool is locked or unlocked anda manual override feature to lock and unlock the tool.

The Claxton tool is 11.5 ft (3.52 m) long, has a maxi-mum OD of 45¾ in., and weighs 5.1 metric tons. It isDNV approved and is verified in accordance with DNV-OS-E101 and API 16F, 6A, 8C, and 7G. The tool is sup-plied as a complete package with a DNV-2.7-1-certifiedcontainer for transportation and storage and a com-bined ATEX-approved hydraulic power unit and umbili-cal reel to power all functions.

Operational advantagesAn important feature of the new tool is that it offers pro-tection for the NT-2 riser connector. This expensivepiece of hardware is at risk of being damaged by theriser when the crane is moving it. The key element of anNT-2 connection is the seal profile located at the top.When the tool is installed on the NT-2 joint, this sealregion cannot be accessed because the tool envelops itand prevents damage through mishandling or fromdropped objects.

The new tool also helps to safeguard against weatherwindow issues, as it can apply tension if sea conditionsworsen during the installation process. In such a situation,a manual tool could not operate to 400 metric tons with-out a specially designed tool mandrel and, more critically,could not maintain tension while being highly pressur-ized. This is not an issue with the new tool because it has

been specifically designed to meet these parameters. Designers also have eliminated some of the opera-

tional use restrictions. For instance, the manual versionrequires over-the-side scaffolding work, which cannot beundertaken at night on some rigs. The hydraulic riser-handling tool has no such operational restrictions andtherefore does not impact decisions regarding when torun or pull the riser system during a drilling campaign.

Slimline tension ringsFurther benefits can be realized from using a Claxtonslimline tension ring, especially when more than oneslot is being drilled at a given time and there is a need to “hop” the riser from one slot to the next. At somepoint, the tension joint needs to be pulled through therotary table. By design, the slimline tension ring doesnot need to be removed to enable the tension joint topass through the rotary table, therefore saving rig time.The tension joint can then be rerun through the rotarytable to make further time savings.

The design

of the new hydraulic riser-

handling tool eliminates the need

for scaffolding and manual handling and offers

protection to the very expensive associated riser connector.

NOMADS 2011 OTC Cocktail Party Monday, May 2nd • 5-7 pm

Reliant Center – Café on the Park(Adjacent to International Visitors Lounge - 2nd Floor)

Tickets still at the bargain price of $40 each

NOMADS is also looking for Sponsors for this event.

Phone: 281-462-0139 • Fax: 281-462-8022Email: [email protected]

All credit cards accepted • Sponsorships welcome!

Platinum: $2,500 or above

Gold: $2,000

Silver: $1,000

Bronze: $500

92-93 Riser-Claxton_92-93 Riser-Claxton 3/23/11 5:00 PM

NOMADSNational Oil-EquipmentManufacturers and Delegates Society

Z h

O 4M P

Bend stiffeners are a common sight on many offshoreplatforms, where they are used to reduce wear and

fatigue in flexible risers and umbilicals. Installing bendstiffeners can be a time-consuming and hazardous busi-ness, especially when divers are involved in securing thebend stiffener connection.

One way around the problem is to use the type ofdiverless bend stiffener connector (DBSC) developed byFirst Subsea Ltd. The company’s latest development isan ROV-less bend stiffener connector designed specifi-cally for risers in crowded production environments andinstallations in the splash zone.

Bend stiffener connectionsFlexible risers either connected to a subsea riser base orthe turret exit of a floating production vessel, for exam-ple, are subject to dynamic environmental loads thatcause the riser to flex around a fixed location. Thismovement, in combination with large axial loads, cancause damage to the riser structure due to overbendingand fatigue. Bend stiffeners mitigate this damage by pro-viding localized stiffness to the flowline and limitingbending stresses and curvature to acceptable levels.

Typically a bend stiffener is a conically shapedpolyurethane molding. Up to 39 ft (12 m) in length and weighing in excess of five metric tons (11 kips),each bend stiffener comprises a conical external profile, cylindrical tip section, and smooth bore to suit the external diameter of the riser.

First Subsea’s DBSC technology, developed in collabo-ration with bend stiffener manufacturer Trelleborg Offshore, enables a fully integrated DBSC design thatmaximizes the engineering performance of both thestiffener and connector elements.

Connector technologyUnlike other bend stiffener connection technologies,which use external locking mechanisms and hydraulicpressure to hold the bend stiffener in place, the DBSCuses a ball and taper type connection. The male connec-

tor is inserted within a female receptacle or I/J tube. Asthe male connector’s balls roll up the receptacle’s wall,tapers drive the balls outward. The tightness of the gripincreases in direct proportion to the load applied. Theconnector is self-aligning and self-energizing, enabling itto be fitted and secured in position without the need fordivers. This approach makes the installation safer andquicker.

The DBSC employs the same connection principleused with First Subsea’s ball and taper-based subseamooring connectors. Developed and deployed in morethan 200 deepwater mooring systems worldwide, themooring connector is subjected to typical minimumbreaking loads of 17,998 kN (4,046 kips).

The DBSC’s ball and taper connection is manufacturedfrom precision-machined forged materials and uses superduplex balls to optimize the connector’s strength andresilience. To protect the connector from corrosion in

Riser bend stiffener connections prepare to go ROV-less

New approach eliminates divers and ROVs for safer and faster installation.

Brian Green, First Subsea Ltd.

The Type II DBSC is being installed on the Neptune LNG project

approximately 10 miles (16 km) off the coast of Gloucester,

Mass. (Images courtesy of First Subsea Ltd.)


RISERTECHNOLOGY

94-95 Riser-FirstSubsea_94-95 Riser-FirstSubsea 3/23/11 5:00 PM


the splash zone, the DBSC has a thermally sprayed alu-minum (TSA) coating. Independent testing has shownthat TSA performs better than electronickel plating orfluoropolymer coating. Anodic protection also can beused to complement any corrosion protection system inplace within the connecting I/J tube.

Although the concept of the DBSC’s connection is rela-tively simple, the connector is optimized for each projectwith respect to the bending moments and load pathanalysis, system finite element analysis, and fatigue analy-sis. In addition, 3-D modeling of the complete connectorenables the production of bending moment and shearstress studies.

Installation loadsThe key engineering challenge in developing the DBSChas been the pull-in load experienced during connec-tion. In-house testing has been conducted to determinethe pull-in loads at different angles and various loads,replicating the loads likely to be experienced by theDBSC in the field.

While pulling the DBSC into the I/J tube side/angled,loads are induced due to the tension in the risers and theangle of the riser. Pull-in loads for the DBSC vary for dif-ferent inclined angles and side/angled loads. It has beenshown that for an angle of 10 degrees or less, the requiredpull-in load is less than the side/angled load. For anglesbetween 10 and 15 degrees, however, the pull-in loadexceeds the side/angled load by a small factor. Even so, the loads experienced are well within the range ofexpected installation loads for these operations offshore.

In general, the larger the riser diameter, the smallerthe available pull-in angle. The pull-in angle also isdependent upon the type of DBSC used.

DBSC connectionsThe first DBSCs were designed to allow the connector tobe fitted within an existing I/J tube and bellmouth dur-ing tieback to an existing facility. The Type I used anROV hot stab hydraulic clamp to activate and lock theconnector’s balls in position and meet the DBSC’storque requirements, preventing the bend stiffenerfrom rotating through the I/J tube.

For newbuild projects, a two part (male/female) con-nection or Type II DBSC was developed, enabling a fullball and taper connection with a smaller footprint wherespace is limited. As both elements of the connection aremanufactured to designed tolerances, this allows for asimpler compact connector. This DBSC is intended forinstallations where the pre-machined female receptacle isfixed to the “I” or “J” tube during the structural fabrica-

tion stage of a floating production, storage, and offload-ing (FPSO) vessel or buoy. The Type II DBSC is designedto release the end fitting once the male DBSC hasengaged within the female receptacle. Unlike the Type I,the Type II connection is used only during installation.Once installed, it does not require a hydraulic lockingmechanism or clamp to hold it in position.

ROV-less DBSC installationBoth the Type I and Type II release DBSC require somelevel of ROV intervention.

The latest DBSC development is an ROV-less Type II for “crowded” turrets or buoys on platforms and FPSOswhere space is either limited or in shallow-water, splashzone environments where ROV installation is impractical.The new Type II DBSC uses an automatic release clamp(ARC) self-latching disconnection system attached to theriser end fitting, which, once engaged with the femalereceptacle, uses a system of rubber springs to maintainthe pre-load on the male connector’s ball configurationand dogs to release the end fitting from the DBSC.

The ARC design addresses the problem of the “weaklink” experienced with some bend stiffener connectorswhere the shear-pin breaks ahead of complete installation.This design also addresses situations where the shear pin istoo strong, which can cause the connector to be over-pulled, leading to installation problems. The ARC DBSCconnector uses an integrated pull-in head locking mecha-nism that automatically de-latches when it is fully con-nected, which eliminates the need forROV intervention during the installation.

Recent testing of the ARC has demon-strated the connector’s viability as apractical solution to the ROV-less instal-lation of risers.

The new Type II DBSC features an automated release clamp.

Recent testing of the ARC has demonstrated the connector’s

viability as a practical solution to ROV-less installation.

For more Riser Technology

articles, visit

EPmag.com

94-95 Riser-FirstSubsea_94-95 Riser-FirstSubsea 3/23/11 5:00 PM

The buzz words among oil and gas exploration companies around the world are “shale plays.”

From Argentina and Brazil in South America to the US and Canada in North America to Poland, England,and Germany in Europe to China and India in Asia and elsewhere, shale plays are ubiquitous and attractivereservoirs with immense economical potential for oiland gas discoveries.

Many shale plays are expansive mild geologic struc-tures that make the discovery process a relatively simpleone. Explorationists in the US have commented thatseismic is not necessary to find oil and gas in theseunconventional shale plays – “… just drill anywhere andyou will find pay.” Be that as it may, finding deposits andsuccessfully exploiting and producing them are two dif-ferent things.

The importance of fracturesA critical ingredient in the successful exploitation andproduction of these prospects is understanding whether

the reservoir is fractured. The orientation and density offractures play an important role in the drilling and pro-duction strategy to follow. Several questions are asked. Isit best to drill horizontally? How do we design the mosteffective borehole trajectory to maximize production? Dowe need to do hydraulic fracturing? How many frac stagesare needed? How will the rock formation fracture?

The traditional way to answer some of these questionsdepended on the study of shear waves and the phenome-non observed in these waves called “shear wave splitting”or birefringence (also known as double refraction).

When shear waves pass through a fractured(anisotropic) medium, they split into two polarizedshear waves that travel at different speeds and “orient”themselves with the fractures. The fast waves orientthemselves parallel to the fractures, while the slow onesbecome perpendicular to them. By carefully measuringthe orientation and speed of the arriving signal, it is pos-sible to determine fracture density and orientation inthe reservoir.

Shear (and converted) wave acquisition and process-ing are expensive and difficult and not yet part of main-stream seismic processing, especially when compared to

compressional (P)data processing. Isthere a simpler andless expensive wayto detect fracturesby using conven-tional P-wave pro-cessing? Whatcould replace thisshear wave splittingphenomenon? Theanswer is the newlydeveloped conceptof offset vector tileprocessing forwide-azimuth data.

The two neces-sary ingredients forthis technology towork are a well-sam-pled wide-azimuth

A specific workflow is needed to construct FracMaps and schematics of the OVT migration. (Images courtesy

of Geotrace)

Fractures detected without shear wavesA new technique provides fracture information at a much lower cost.

Jaime A. Stein, Geotrace


techWATCH

96-99 TechWatch-Geotrace_96-99 TechWatch-Geotrace 3/23/11 5:00 PM


acquisition and a wide-azimuthal seismic processing sys-tem that includes an orthorhombic migration and veloc-ity analysis.

It has been documented elsewhere that if seismic dataare acquired with good azimuthal coverage such thatreservoirs can be illuminated from different directions,enough information can be elucidated from the behaviorof the compressional waves traveling through the rocks indifferent directions to help determine the orientation(and perhaps the density) of the fractures.

Similarly to the shear wave splitting effect,the compressional waves travel at differentspeeds, depending on whether they are mov-ing along (fast) or against (slow) the frac-tures. Furthermore, it is possible to measurethe propagation velocities of these compres-sional waves in different directions anddetermine the fracture orientation.

This new technology can be used to deter-mine fracture orientation. It is based on theuse of offset vector tiles (OVT), orthorhom-bic prestack time migration, and carefulanalysis of the generated offset migratedgathers (OMG).

OVT, orthorhombic migrations, OMGWhen good azimuthal coverage exists in aseismic survey, it is possible to construct(minimal) datasets or OVTs that preservethe azimuthal and offset information aftermigration. When these OVTs are migrated,they generate OMGs. OMGs are the vectorgeneralization of the traditional migratedgathers. They represent the subsurface

as seen by different offsetsfrom different directions(azimuths). If the velocityand anisotropy models arecorrect, these gathers shouldbe flat. The deviation fromflatness indicates the pres-ence of an incorrect velocity,probably due to anisotropyin the vertical and horizon-tal directions.

In traditional migratedgathers, vertical anisotropy (VTI) expresses itself as“hockey sticks” in the offset domain, requiring the intro-duction of an anisotropic correction into the migration traditionally called (eta) �.

The analysis of OMGs immediately demands the introduction of additional anisotropic corrections ontop of VTI. The two parameters chosen are the horizon-tal propagation velocities in two different directions,referred to as VH

fast and VHslow. The combined presence

An OMG is sorted into offset and

azimuth displaying VT and HTI

anisotropy.

A velocity ellipsoid describes orthorhombic anisotropy. There is one of these for

every point and sample.

techWATCH



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of horizontal anisotropy (HTI) and VTI anisotropy isorthorhombic anisotropy. It can be argued that thisorthorhombic anisotropy is pervasive to the earth as itdescribes the natural symmetry (or lack thereof) occur-ring in a vertical depositional flat-layer environment thatundergoes fracturing at a later stage.

Through a process called a surface-fitting algorithm, itis possible to find these velocities. One way to visualizethese new corrections together with VTI is as a 3-Dvelocity ellipsoid with different sized semi-major andsemi-minor axes and with different orientations. Everypoint in the survey has a tetrad of values (Vv, VH

fast, VHslow;

and �) describing such an ellipsoid.By selecting the orientation and the semi-major axis

magnitude, it is possible to construct a simple represen-tation of the anisotropy, called a FracMap. A time sliceacross one of these volumes shows a formation of direc-tional patterns that can be interpreted as fractures.Waves move fast along this direction and slow perpendi-cular to them, hence the connection to fractures.

This velocity vector is used to determine fracture orien-tation in a reservoir and presents an attractive alternativeto shear wave splitting. Although shear waves can producesimilar information, the ease of processing wide-azimuthP-waves by well-known and understood techniques makesthis a more desirable processing alternative.

References available.

Zoomed-in FracMap (timeslice) shows fracture orientation and

intensity (thickness of tick mark)


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New PDC bit engi-neered for shale A new family of PDCbits that targets shaleplays has been devel-oped by Smith Bits.The Spear shale opti-mized steel-body PDCbit addresses the mostpersistent challengesof shale well bit per-formance – steerabilityand penetration rate.

The new IDEAS cer-tified cutting structureenhances the direc-tional response of thebit in both the curveand lateral hole sec-

tions. Lo-Vibe depth-of-cut control inserts back up thecutters at the outer blade edges to improve bit life. Builtaround a steel body that allows reduced blade width andincreased blade height, the bits feature expanded flow-by area between the bit body and the borehole wall. Thehydraulically optimized design provides 66% more junkslot area and boosts face volume by 26% for enhancedcuttings removal, the company says. Face volume areaalso is boosted by 26%. The bit’s bullet-shaped profilereduces the opportunity for bit balling and nozzle plug-ging to improve penetration rates.

Because of the abundance of cuttings generated bythe bit at high penetration rates, hydraulics capabilitywas boosted using optimized nozzle placement to ade-quately clean the cutting structure face and avoid issueswith nozzle plugging. Minimizing cuttings beds alongthe low side of the lateral is a critical attribute for highpenetration rates, reduced axial and torsional friction,and maximum effective use of hydromechanical energyto deliver improved performance over conventionalPDC bits. www.slb.com/spear

New ropes help during subsea mooring failuresRopes made with DSM Dyneema’s ultra-high molecularweight polyethylene are being used on many facilities inthe offshore oil and gas industry. The company says usersare finding this rope invaluable when original steel wirerope and chains that secure mooring legs break or sufferdamage.

The backup lines are installed as a safety feature untilregular maintenance can be carried out. The system isdesigned to retain the floating production, storage, and

offloading unit in position and to maintain production,gaining time for the operator to mobilize the requiredvessels and equipment to replace the broken wire leg incase one of the wires fails due to its reduced strength.www.dyneema.com

Project tracker provides suitable data management processesBlueback Reservoir has released the Blueback ProjectTracker plug-in for Petrel, allowing data managersresponsible for maintaining order and structure of thePetrel project files on various network disks to track andmonitor projects from all of their Petrel users. It is accessi-ble from outside Petrel and provides extensive informa-tion about project content and history.

With a powerful and customizable search engine, theplug-in quickly identifies data inconsistencies and dupli-cations and references project relations. It also helps tocontrol and manage large numbers of Petrel projects onvarious disks. www.blueback-reservoir.com

System helps mitigate lost-circulation risksLost circulation can occur during drilling or primarycementing procedures, resulting in ineffective mudremoval and poor zonal isolation and increasing theneed for expensive and time-consuming remedialcementing jobs. The Schlumberger Losseal family of

techTRENDS

The Spear drill bit has a sleek pro-

file; thin, high steel blades; and wide

junk slots ideal for shale well drilling.

(Photo courtesy of Smith Bits)

Losseal creates an impermeable seal to cure losses. (Image

courtesy of Schlumberger)

100-102 TechTrends_100-102 TechTrends 3/23/11 5:01 PM


reinforced composite mat pills allows operators to miti-gate the risk associated with lost-circulation issuesencountered not only while cementing but also whiledrilling. The Losseal system combines fibers and solidsinto a specifically engineered, flexible fiber additive pill.The pills use synergy between the physical characteris-tics of fibers and solids, plugging fractures that causepartial or total losses while drilling or cementing.

The system also creates an impermeable grid strongenough to withstand additional pressure from mud density increases as well as any additional pressure fromfuture drilling or cementing operations. It reducesdrilling downtime caused by circulation losses whileaddressing large losses in fissures, saving thousands ofbarrels of mud during placement and reducing nonpro-ductive time, the company says.

Traditional lost-circulation fiber treatments rely onknowing the fracture width during bridging and plug-ging. The combination of fibers with different mechani-cal properties and high solids content makes the Lossealsystem design less sensitive to fracture sizes, with thesolid particle size being optimized to plug the networkof fibers as opposed to the fractures. Plugging-efficiencytests are conducted prior to the first application. Addi-tionally, the system can be pumped through most bot-tomhole assemblies, eliminating the need to pull out of the hole and run open-ended drillpipe. www.slb.com

Wellbore cleanout product line expands Bilco Tools Inc. has expanded its wellbore cleanout toolproduct line, including Big Boy riser waste retrievers,which the company says have one of the largest solidsretrieval capacities in the industry. Strong Boy magnettools are equipped with powerful, high-temperature mag-nets to remove ferrous debris from the well bore, and BigStrong Boy debris trappers are a combo tool featuring thesolids retrieval and ferrous debris trapping capabilities ofthe Big Boy waste retriever and Strong Boy magnet tool.

Additional tools in the line include the Swift Boy jet tool series, the Clean Boy filter basket, Flow Boy circulating tools, Slim Boy swivel subs, the Swift Boy circulating tool, and Czech Boy ball type flow checksubs. www.bilcotools.com

Drill-through reaming system enhances wellbore integrityDrillers face an increasing demand to run casings togreater depths and at higher angles. Tools that enabledrilling teams to land downhole assemblies at targetdepth the first time can decrease drilling costs. Oftenconventional methods are not practical or prudent – for

example, the size or length of the casing can make itimpossible to rotate on smaller rigs, and the well pathcan prevent rotation.

Deep Casing Tools has launched the first drill-throughtool to ensure casing to target depth, allowing wells tobe drilled as planned and enhancing well integrity. Man-ufactured as a single body from high-strength steel, theTurbocaser Express is a rugged downhole tool that canream casings through obstructions, is fully HP/HT com-pliant, and works with any drilling fluid without deterio-ration in power output, reliability, or performance. Afterreaming casing to target depth, the tool can be drilledthrough in minutes with standard drill bits after normalcementing in one operation. www.deepcasingtools.com

Fastener enhances reliability in extreme temperaturesSpiralock’s new self-locking threaded fasteners enhancereliability by combating vibration, thread loosening, andextreme temperatures, while easing assembly, mainte-nance, and inventory management without the need for secondary locking features.

The thread form adds a 30-degree wedge ramp at theroot of the thread that joins standard 60-degree threadfasteners. The wedge ramp allows the bolt to spin freelyrelative to the threads until tension is created in the fas-tener. The crests of the standard thread form are drawntightly against the wedge ramp, eliminating radial clear-ances and creating a continuous spiral line contactalong the entire length of the thread engagement. Thiscontinuous line contact improves resistance to vibra-tional loosening, axial-torsional loading, joint fatigue,and temperature extremes. www.spiralock.com

— Ashley E. Organ, Associate Editor

techTRENDS

The Turbocaser Express can ream casings through obstructions,

is fully HP/HT compliant, and works with any drilling fluid.

(Image courtesy of Deep Casing Tools)



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While the southern coast of Australia continues totick over with relatively small but steady activity,

and with New Zealand searching via licensing roundsoffering frontier acreage to inject life into its somewhatstagnating and already modest oil and gas scene, Aus-tralia’s western shore is a totally different story.

Investment upswingWith operators such as Woodside Energy, Chevron,ExxonMobil, Shell, and BHP Billiton increasinglyfocused on either expanding established shallow-waterLNG schemes or developing mostly deepwater mega-projects offshore Western Australia to meet continuallyexpanding gas demand – particularly from Asia – theresult has been a huge upsurge in current and predictedspending. An estimated US $120 billion has been com-

West coast gas bonanza lights upAustralia’s offshore future

The west coast of Australia has emerged from the shadows to become a major E&P hotspot forthe offshore oil and gas industry, dominating the Australasian region as both domestic andinternational majors sink billions of dollars of investment into several massive LNG projects.

Mark Thomas, International Editor

REGIONAL REPORT:AUSTRALIA & NEW ZEALAND

The Greater Gorgon, Wheatstone, Pluto, and NWS projects are surrounded by a substantial number of established discoveries such as

Scarborough and East Artemis, along with many other smaller discoveries and prospects that will eventually feed future expansions of

the main LNG projects either already established or under development. (Image courtesy of MEO Australia)

103-109 RegionalReport-AustNZ_103-109 RegionalReport-AustNZ 3/23/11 5:01 PM


mitted or is under consideration for these projects.This newer breed of projects now emerging also is

proving to be as pioneering and challenging technologi-cally as anywhere else in the world, with floating LNG(FLNG) solutions, deepwater tension-leg platforms(TLPs), and long-distance subsea tiebacks to onshoreLNG plants currently either under way or on the draw-ing board. All of these are leaning on knowledge andexperience gained from the world’s established offshorebasins, with most of the operators and contractors draft-ing in experienced staff from elsewhere to ensure suffi-cient knowledge and technology transfer.

This also has lead to significant growth in requiredinfrastructure and logistical support in and aroundPerth, with many manufacturers and service and supplycompanies either establishing or expanding their pres-ence in the area to position themselves for a slice ofwhat looks set to be a long-term growth market.

Major public investment in recent years in the Aus-tralian Marine Complex just south of Perth has given

service companies access to common-user infrastruc-ture, including a recently commissioned $60 millionfloating dock measuring 325 ft by 174 ft (99 m by 53 m)and capable of lifting vessels up to 12,000 metric tons.This will enable underwater subsea structure treatment,while a new $35 million service and supply base is beingdeveloped to support offshore projects with a servicewharf to accommodate roll-on/roll-off vessels and a473,612-sq-ft (44,000-sq-m) staging area.

Development builds on gasNatural gas has become increasingly important for Australia, both as a source of export income and as adomestic energy source. Approximately 50% of thecountry’s gas production is exported.

Oil is a different story since Australia is a net importerof crude. Recent forecasts state that Australian oil pro-duction between 2010 and 2020 will fall by 29.21%, withcrude volumes peaking in 2013 at 640,000 b/d beforedeclining to 395,000 b/d by the end of the decade.



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Gas production, how-ever, is expected to soarfrom an estimated 1.77MMcf in 2010 to possibly3.88 MMcf by 2020. With10-year demand growthdomestically of 30.52%,this means an exportpotential rising from anestimated 812 Mcf to 2.65 MMcf, all expected to beLNG. Western Australia currently accounts for nearly9% of global LNG production, but that figure certainlywill rise.

Flagship LNG mega-projects such as the Chevron-operated $37 billion Greater Gorgon project are leadingthe way. One of the largest single-resource investmentsin the world, Chevron is partnered by ExxonMobil and

The FLNG design is planned

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(Image courtesy of Shell)


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Royal Dutch Shell. The project entails subsea produc-tion from several shallow and deepwater fields withreserves of 40 Tcf of gas. Processing facilities will pro-duce 15 million tons per annum (MMtpa) of LNG forexport and 300 terajoules of gas per day for domesticconsumption.

Jim Blackwell, executive vice president, Technologyand Services, at Chevron, said the Gorgon project playsa big role. “Looking at Gorgon, it’s the centerpiece ofour growth story. Everything about this project is huge:resources, production, and infrastructure. The Gorgonand Io/Jansz gas fields hold more than 40 Tcf of gas, theequivalent of 7 Bbbl of oil,” he said.

Gorgon’s project workscope covers a three-train 15MMtpa LNG facility, a domestic gas plant and maximumproduction of 2.6 Bcf/d of gas and 20,000 b/d of con-

densate, with startupexpected in 2014.

“Our first three trains atGorgon are expected toproduce 450,000 boe/d,”Blackwell said, adding thata final investment decision(FID) on a fourth train forGorgon would be reachedbefore the end of 2013.

That decision will havebeen helped by a string of10 discoveries made byChevron over the past 18months. At the end of2010, Chevron’s estimatedtotal resource for theGreater Gorgon area wasalmost 60 Tcf, he added,with enough potential for afifth train for Gorgon.

Chevron’s other keyproject in the area is its$23 billion WheatstoneLNG development. An FIDon Wheatstone’s first andsecond trains is expectedto be made later this yearon what will be a two-train,8.9 MMtpa LNG facilityplanned to start up in 2016at a forecast rate of260,000 boe/d.

The project consists ofthe development of four

fields – Wheatstone, Iago, Brunello, and Julimar – via anoffshore processing platform that will pipe raw gas to anonshore plant.

Chevron says Wheatstone also is well-positioned for athird LNG train and further expansion.

Another equally active player offshore Western Aus-tralia is Woodside Energy, which is spending $12 billionon its Pluto LNG project, while also proceeding with theestimated $30 billion development of its Browse LNGscheme, among others. Pluto is the most advanced of allthe schemes under way, with an annual capacity of 4.3MMtpa and due to come onstream in August 2011.

Much larger is Woodside’s estimated $30 billionBrowse LNG development, a world-class project alsoentailing one of the largest deepwater schemes in themarket.



Western Australia’s lineup of LNG projects currently under way represents more than $120 billion in

terms of projected expenditure. (Image courtesy of the Department of Mines and Petroleum, Govern-

ment of Western Australia)




Browse is a joint venture (JV) of operator Woodside,BHP Billiton, BP, Chevron, and Shell. Woodside hasdescribed the project as a “game changer” for the com-pany, essentially because Browse will double the com-pany’s current equity share of LNG production.

The overall project – if it receives an FID as plannedmid-2012 – will include three TLPs (two initially and thethird in a later phase) in deep water, as well as twobridge-linked central processing platforms in approxi-mately 328 ft (100 m) water depth, more than 746 miles(1,200 km) of subsea pipeline infrastructure, and athree-train LNG facility 202 miles (325 km) onshore.

The TLPs will process gas and condensate from threefields in the Browse Basin, starting with the Brecknockand Calliance fields and then the Torosa field. The fieldsare estimated to contain a combined contingent resourceof 13.3 Tcf of dry gas and 360 MMbbl of condensate.

A handful of contracts was issued recently for key partsof the project. Fluor Corp.’s Fluor Offshore Solutionsunit was awarded a front-end engineering and design

(FEED) contract in partnership with McDermott Inter-national for the central gas processing facility includingsteel jackets, a compression platform, and a utilitiesaccommodation platform. Fluor teamed with McDer-mott for the steel jackets design and float-over installa-tion. Work is under way, and completion is expected bythe end of 2011.

The two initial TLP dry-tree units are the subject ofparallel FEED studies being conducted by Aker Solu-tions and Modec. An engineering, procurement, con-struction, and installation tender will be submittedmid-year, with expected contract award by the end of2011.

Both floating production facilities, which will be con-figured for subsea tieback to the central processing com-plex, also will pioneer the first use of TLPs offshoreAustralia.

Offshore gas liquefaction – otherwise known as FLNG– is a technology that has just barely moved off the draw-ing board and conceptual studies to become a firm proj-


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ect option, and Western Australia is atthe forefront of its first planned use.

One of its main proponents is Shellwith its plans for the Prelude project,also in the Browse Basin. The project isscheduled for an internal FID before theend of 2011 and would be the world’sfirst FLNG facility in action.

The operator currently is in the FEED phase for the unit, which is beingdesigned to produce 3.6 MMtpa ofLNG, 400,000 metric tons per year ofliquefied petroleum gas, and 1.3 MMtpaof condensate. First LNG is expected toflow by 2016.

Following closely on its heels isanother FLNG project in which Shell isinvolved – the Woodside-operated Sun-rise LNG JV. The Greater Sunrise fields,which straddle the Australian and EastTimorese maritime border, are esti-mated to hold more than 5 Tcf of gasand 226 MMbbl of condensate.

The Sunrise JV recently selected adevelopment concept to produce thereserves using FLNG technology andsaid the project has robust economics.However, formal government and regu-latory approvals still are required beforeit is considered a firm project.

FLNG technology is set to become anincreasingly employed solution for com-mercializing remote or “stranded” gasreserves, and Australia is primed tospearhead its use.

More conventional floating oil-pro-duction projects will continue to beemployed.

Recent examples of smaller yet sub-stantial floating production develop-ments include BHP Billiton’s $2 billion,96,000 b/d Pyrenees oil field in thesouthern Carnarvon Basin and ApacheEnergy’s $700 million, 40,000 b/d VanGogh oil field in the Exmouth Basin.Both began production in early 2010.In October 2010, Van Gogh was shut infor unexpected repairs to be carried outto the Ningaloo floating production,storage, and offloading (FPSO) unit,but came back onstream earlier in 2011.



More zeal needed for New Zealand

The first well of the modern era in New Zealand was drilled inTaranaki in 1966, but an indicator of this remote island nation’s

current situation is that oil still is being produced from only one basin.With annual production in 2008 and 2009 of 55,000 b/d – dominated

by output from its Tui, Pohokura, and Maui fields – and a domestic con-sumption figure of 148,000 b/d, the country’s need to grow productionlevels and raise current proved reserves of 190 MMbbl is clear.

There have been signs in recent months that things finally could bestarting to change. Bearing in mind recent exploration successes else-where in the world (and in remote locations), when two major playerslike Petrobras and Anadarko Petroleum Corp. quietly slide into an areafor the first time, others should take notice.

According to New Zealand’s Energy and Resources Minister GerryBrownlee, “New Zealanders have believed that as a country we arebereft of natural resources in comparison with places like Australia,” hesaid. “Nothing could be further from the truth.

“The reality is that New Zealand has the fourth largest exclusive eco-nomic zone in the world, with 15 recognized basins that are potentiallycapable of producing hydrocarbons. Incredibly, only one basin –Taranaki – currently has producing fields.”

Brownlee added that the most exciting development in the last yearwas the entry of Petrobras and Anadarko into the country.

Petrobras was awarded 100% of exploration permit Block 2 in thefrontier Raukumara Basin, while Anadarko farmed in for 50% of threepermits operated by Origin Energy in the Deepwater Taranaki andCanterbury basins.

“The fact that these two companies have been willing to invest herehas really sent a signal to the rest of the world that New Zealand isprospective and open for business,” Brownlee said.

Few in the upstream industry doubt that the country’s offshore sec-tor has significant oil and gas potential, especially in its frontier deep-water zones. A study in 2009 by the Institute of Geological and NuclearSciences estimated there is a 90% chance that reserves totalling 1.9Bbbl of oil remain in New Zealand, and a 50% chance that there are 6.5Bbbl. Most of these estimated undiscovered reserves are believed tobe in deep water in the Great South and Deepwater Taranaki basins.

It has been the sheer geographical remoteness of New Zealand thathas held back the progress of its small but robust domestic E&P indus-try, with many international oil companies reluctant to bear the costsof shipping equipment to the isolated nation and shipping any oil fromit to faraway refineries.

For many observers, it is the exploration of the country’s frontierbasins by players such as Petrobras and Anadarko, along withincreased use of the latest production optimization and brownfieldtechnology to extend the life of its existing assets, that holds the key toits energy future and indicates that the E&P industry is prepared forthe long haul in New Zealand.



Operators such as Woodside continue to pick upreserves around their other existing floating productionprojects offshore Western Australia, with the companyconsidering either a subsea tieback or standalone FPSOsolution for its deepwater Laverda oil discovery (40MMbbl of recoverable reserves). An FID will be made bythe end of 2011.

While many markets in Southeast Asia are showingsome signs of growth, Australia’s sector – driven by anexplosion in activity offshore its west coast – is in the

midst of a transforma-tion from a provincewith potential to aworld-class gas power-house.

Petrobras quietly stepped into New Zealand’s frontier deep waters

for the first time in 2010, taking 100% of Block 2 in the Raukumara

Basin offshore North Island. (Image courtesy of Petrobras)




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internationalHIGHLIGHTS

Pacific Rim

Petronas hits Sarawak doublePetronas has made oil and gas discoveries with the NC3and Spaoh-1 wells in blocks SK316 and SK306 offshoreSarawak, East Malaysia. The NC3 wildcat well was drilledto a depth of approximately 13,123 ft (4,000 m) belowsea level, and a subsequent appraisal well brought a sig-nificant discovery in Block SK316 with early estimates of2.6 Tcf of net gas in place. The Spaoh-1 well was drilledto approximately 9,843 ft (3,000 m) in Block SK306 andshows similar promise for both oil and gas. The prelimi-nary evaluation indicates approximately 100 MMbbl ofoil and 2 Bcf of gas in place.

Gas shows in PNGEaglewood Energy Inc. has hit gas in the Ubuntu-1 wellin PPL 259 approximately 11 miles (17 km) east of theKetu and Elevala gas condensate discoveries in PapuaNew Guinea (PNG).

Oil, gas discovered offshore VietnamJapan’s JX Nippon Oil & Gas Exploration Corp. hasmade an oil and gas discovery with the Dai Nga explo-ration well in blocks 05-1b and 05-1c offshore south Vietnam. The structure is approximately 9,514 to 11,811ft (2,900 to 3,600 m) below sea level in 394 ft (120 m)water depth. Oil and gas accumulations were confirmedby drillstem tests.

Zola gas discoveryTap Oil has made a gas discovery with the Zola-1 well inpermit WA-290-P in the Carnarvon Basin offshore West-ern Australia. The well was drilled to a depth of 14,032 ft(4,277 m) in 935 ft (285 m) water depth targeting theMungaroo formation, which will be intersected atapproximately 14,108 ft (4,300 m) below sea level. Thewell has encountered indications of hydrocarbons, sug-gesting the presence of a gas column from the top ofthe primary target.

Cooper Basin oil findCooper Energy’s Parsons-3 well – the first well in the

2011 PEL 92 area drilling campaign – has intersected a30-ft (9-m) oil column in the Namur reservoir in Aus-tralia’s Cooper Basin. The well was drilled to 4,626 ft(1,410 m) total depth. The Parsons field currently isproducing approximately 1,100 b/d of oil from twowells in the Namur reservoir.

Central Asia

ONGC hits Indian trioIndia’s ONGC has made three discoveries. The Aliabet-2well in Block CB-OSN-2003/1 was drilled to a depth of6,913 ft (2,107 m) in the Cambay Basin in northwestIndia. Initial production totaled 455 MMcf/d of gas and212 cf/d of condensate. In the Krishna Godavari (KG)Basin in southeast India, the company hit oil and gaswith the Malleswaram-1 well in the PEL Block 1A. Thewell produced 1.68 Mcf/d of oil and 393 Mcf/d of gas.In the offshore shallow-water KG Basin, the GS-29-6 wellproduced 20 Mcf/d of oil and 4 MMcf/d of gas.

Uzbekistan oil findTethys Petroleum Ltd.’s NUR96H2 horizontal develop-ment well at the North Urtabulak field in Uzbekistanhas flowed more than 1,100 b/d of oil and now is beingput on production. The well was drilled to a total depthof 10,039 ft (3,060 m), with a producing section of 1,434ft (437 m) of lateral hole.

Siberian double for RosneftRosneft has discovered two new oil and gas fields at theSanarsky and Preobrazhensky license areas in EasternSiberia. Preliminary data suggest that the Sanarskoye


For additionalinformation onthese projects

and other globaldevelopments:

Tethys is developing the North Urtabulak field in Uzbekistan.

(Image courtesy of Tethys Petroleum Ltd.)

110-114 Highlights_110-114 Highlights 3/23/11 5:01 PM


and Lisovskoye fields each have initial recoverablereserves of approximately 586 MMbbl of oil.

South America

Oil flows in Santos Basin Petrobras has discovered a new accumulation of good-quality 26º API oil in the Santos Basin presalt reservoir,approximately 152 miles (244 km) off the coast of Rio deJaneiro State, Brazil. Well 4-BRSA-818 (4-RJS-668), namedMacunaíma, was drilled in 7,001 ft (2,134 m) water depthand confirmed reservoirs at 18,635 ft (5,680 m).

OGX hits shallow-water oil OGX has identified the presence of hydrocarbons inwell 1-OGX-31-RJS in the BM-C-41 block in the shallow-water Campos Basin approximately 50 miles (80 km) off-shore Brazil. The Ocean Ambassador semisubmersibledrilled the well to a total depth of 12,421 ft (3,786 m) in446 ft (136 m) water depth.

A 489-ft (149-m) oil column with approximately 157 ft(48 m) of net pay was encountered in the Albian sec-tion, and a 194-ft (59-m) column with approximately 75ft (23 m) of net pay was encountered in the Aptian sec-tion, both in carbonate reservoirs.

Bolivia field comes onstreamTotal has brought the Itaú gas and condensate fieldonstream in Block XX (Tarija Oeste), 249 miles (400 km) south of Santa Cruz, Bolivia, in the AndeanCordilleras foothills. The first phase of development is designed to produce 53 MMcf/d of gas.

Africa

Algeria gas flowsPetroceltic’s AT-4 well has tested gas from two zones inthe Ain Tsila field in the Isarene permit (blocks 228 and229a) in Algeria. The well encountered a gross gas col-umn of 509 ft (155 m) with no gas-water contact. The twozones in the Ordovician reservoir had a combined flowrate of 1.35 MMcf/d of gas and 450 b/d of water on a 48-in. choke.

Ghana oil for TullowTullow Oil Plc’s Teak-1 exploration well has discoveredapproximately 240 ft (73 m) of net hydrocarbons in the West Cape Three Points license offshore Ghana. The Atwood Hunter semisubmersible drilled the well to a total depth of 10,400 ft (3,170 m) in 2,848 ft (868 m)water depth.

In the shallower reservoirs, the well intersected 20 ft (6m) of oil pay in the upper zone and 108 ft (33 m) of gaspay with an underlying 49-ft (15-m) 40º API oil leg in thelower zone. In the deeper reservoirs, the well intersected46 ft (14 m) of gas-condensate pay in two separate zonesand 16 ft (5 m) of 32º API oil pay in a deeper level.

Moroccan gas discoveryCircle Oil’s #6-DRJ exploration well in Morocco’s Seboupermit in the Rharb Basin has hit gas in the Base Guebbastarget. The well flowed 5.36 MMcf/d of gas on a 26⁄64-in.


The Macunaíma well discovered 26º API oil in the Santos Basin.

(Image courtesy of Petrobras)

The Teak-1 well encountered approximately 240 net ft of oil,

condensate, and natural gas pay in five separate Campanian-

and Turonian-age reservoirs. (Image courtesy of Anadarko

Petroleum Corp.)



H A R T E N E R G Y

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choke from perforations between 3,419 and 3,442 ft(1,042 and 1,049 m) from a net gas pay of 14.8 ft (4.5 m).

Anadarko hits again offshore MozambiqueAnadarko Petroleum Corp. has made another large dis-covery offshore Mozambique. The Tubarão discoverywell – the fourth in the company’s Offshore Area 1 cam-paign – hit 110 net ft (34 net m) of dry gas pay. Seismicindicates the field could be as large as 15,000 acres andcould contain 1 to 1.2 Tcf of recoverable reserves.

Europe

Producer offshore GreeceEnergean Oil & Gas has completed the PA-35 infill wellin the Prinos field in the Aegean Sea offshore Greece.The GSP Saturn jackup drilled the well to a total depthof 9,760 ft (2,975 m), confirming the presence of the Band C reservoirs at 9,380 and 9,544 ft (2,859 and 2,909m) measured depth, respectively. The PA-35 well pro-duced 1,000 b/d of oil; total reserves for Prinos are esti-mated at 1.8 MMbbl.

Statoil find near GullfaksStatoil has found gas and condensate in Rimfaks Valley inthe middle sector of the Norwegian North Sea with well34/10-53 S. The well was drilled to a vertical depth of12,621 ft (3,847 m) below sea level in 446 ft (136 m)water depth and confirmed a column of approximately984 ft (300 m) in good-quality reservoir rocks. The discov-ery is estimated between 19 and 75 MMboe recoverable.

Middle East

Hydrocarbons flow in YemenDNO International has hit hydrocarbons with the Gab-

dain-1 exploration well in Block 72 in Yemen. The wellwas drilled through to a total depth of 11,434 ft (3,485m) measured depth. The well produced approximately130 to 180 b/d of 39° API oil at the end of a five-day test.

Kurdistan oil discoveryGulf Keystone Petroleum has completed the Shaikan-3shallow appraisal well in the Shaikan block in Kurdistan.The well flowed 9,800 b/d of oil on a 128⁄64-in. choke witha flowing tubing pressure of 264 psi.

North America

Louisiana well completedPhoenix Exploration Co. has completed the #1 StateLease 20221 well in St. Mary Parish, La. Initial potentialfrom the well was 15.24 MMcf/d of gas, 122 b/d of 40.4ºcondensate, and 20 b/d of water through perforationsat 18,194 to 18,314 ft (5,546 to 5,582 m) in the Cibicidesopima.

Gas flows from Mississippi wellMoon-Hines-Tigrett Operating Co. has completed the#1 East Dexter 34-13 well in the East Dexter field in Sec-tion 34-2n-13 w in Marion County, Miss. The LowerTuscaloosa well was drilled to 9,605 ft (2,928 m) andflowed 1.3 MMcf of gas.

Alabama wildcat hits oil, gasMidroc Operating Co. has drilled the #30-4 Mary Mackwildcat well to 11,920 ft (3,633 m) in Little Cedar Creekfield in Conecuh County, Ala. The well initially flowed159 bbl of 56º gravity oil and 620 Mcf of gas from Nor-phlet perforations between 11,770 and 11,790 ft (3,587and 3,594 m). No water flowed from the well.

Gulf of Mexico

Hess submits deepwater proposalHess Corp. has submitted a plan to drill three deepwaterexploratory tests across three blocks in the deepwaterGulf of Mexico in approximately 1,282 to 2,075 ft (391to 632 m) water depth. The first proposed wildcat well is slated for a surface location in the southwestern areaof Green Canyon Block 70. A second test is scheduledfor a site in the western portion of Block 25, and a thirdlocation is planned for the northeastern portion ofBlock 69.

The development wells in the Prinos field offshore Greece are

conventionally deviated to cover the entire anticlinic struc-

ture. (Image courtesy of Energean Oil & Gas)



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on theMOVE


Apache Corp. has appointed Rod Eichler president and COO and Roger Plank president and CCO.

Howard Hoffmann has beenpromoted to CEO of UnitedVision Logistics.

President and COO Christopher J.Wiernicki has been appointed CEO of ABS.

Mainland Resources Inc. has namedMichael J. Newport CEO and director.

The Marine Well Containment Com-pany has appointed Marty Massey CEO,Astley Blair CFO, Dan Smallwood COO,Charles Miller CTO, and CarmineDulisse HSE officer.

John P. Anerousis has returned as chief business development officer of Coastal Flow Gas Measurement.

Red Spider has named David Allan COO.

TerraSpark Geosciences has appointedRobert Stevenson COO.

MicroSeismic Inc. has promotedMichael ThorntonPhD (left) to CTO.

Chief geophysicist Michael Mueller(right) will succeed him as vice presi-dent of Analysis.

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MARKETING | SALES | CIRCULATION

Robert Burke, industry journalist, passedaway on March 12, 2011. For more than 20 years,Burke was editor-in-chief of Offshore magazineand served numerous times on the board ofdirectors for the National Ocean Industries Asso-ciation in Washington, DC. He was president andon the board of directors for the Association ofPetroleum Writers and was a founding memberof the technical committee for the annual sem-inar Deep Offshore Technology. After his time at Offshore, Burke joined Hart Publications assenior editor to open a Houston office for Petro-leum Engineer International magazine.

In Memoriam

115 Onthemove_Layout 1 3/23/11 5:29 PM

r-I 17- P


As hydrocarbon reserves become harder to recover,technological expertise will keep oil supplies flowing,

solving the challenges facing the global industry. New technology is fundamental in supporting efficient

production, and staying ahead in the R&D game is notonly the responsibility of the industry – reforms are neededon a fiscal as well as a national level. With the collapse ofbank profits and slow post-recession recovery, the oil andgas sector now is the biggest contributor of corporate tax tothe UK Treasury.

Research shows that UK production still can meet muchof the domestic energy requirement. More hydrocarbonscan be extracted; however, this depends on the right taxincentives for oil and gas operators – not subsidies, but tax breaks.

The rules regarding R&D expenditureneed to be re-examined to boost projectactivity on the UK Continental Shelf(UKCS). Currently, if an operator con-tracts research from a university, the com-pany can obtain tax credit. However, ifthe R&D work is carried out by a contrac-tor, the contractor receives the tax credit.

A more fair system would award the taxcredit to the party that actually pays forthe R&D program.

Consideration also should be given to increasing the lev-els of tax incentives for both R&D and technology demon-stration. Much can be learned from Norway’s successes inthis area, particularly with regard to making field trialsmore tax-efficient.

Today much activity is geared toward small fields. But recent news of big finds is a reminder that althoughthe Central North Sea is mature, it is very much alive and healthy.

In the past, it has been estimated that 5.6 Bboe reservescould be made economic over a five-year period in theUKCS through the deployment of new technologies. It iswidely recognized that new technology has been responsi-ble for reducing the risks involved in exploration and slash-ing drilling times by half. These advantages alone are

critical factors in encouraging companies to adopt technol-ogy as the way forward.

ITF fosters the need for collaboration between operat-ing companies, large service companies, small andmedium-sized enterprises, universities, and academia todistribute the risks and benefits of technology innovation.

In the UK, there are many organizations working totheir own agendas. A national coordinated approach likeNorway’s that annually identifies and addresses one set of industry challenges would be a better way forward forthe UK. A country-wide strategy for new technology isrequired to get the remaining reserves out of the ground.

All parties should agree to a set of goals so a united,strategic approach to achieving these objectives becomes a reality. Although a lot of work is being done in the UK, it is carried out in a very fragmented manner. The countryneeds to focus on identifying and understanding the indus-

try’s technology needs as well as promot-ing the role of an intermediary, such asITF, among the organizations involved.

This type of umbrella model exists in Norway – OG-21 – where partneringamong government, oil companies, thesupply industry, research institutions,and academia acts as a catalyst, ensuringnew technology is developed and testedand that solutions are implemented.

Increased investment in technology is needed by all UK stakeholders to pro-

duce a realistic impact in terms of enhanced investmentand recovery in the UKCS.

Because full-scale testing must be completed before atechnology can be accepted into the market, commercial-izing technology to the oil and gas market is costly andtime-intensive, requiring nearly twice as long as in othersectors. This is why UK end-users must demonstrate com-mitment to field trials, pilot new technologies, and over-come the risk-averse mood, which can be very inhibiting.

Now is the time when all those involved in UKCS opera-tions, including the Department of Energy and ClimateChange and HSE, need to collaborate to develop thetechnologies needed for the North Sea Basin. Withoutthis unified approach, it will be very difficult for the coun-try to develop much of the remaining 5.6 Bboe.

R&D needs government boostNew technology is the way forward in producing the remaining reserves in maturing oil and gas fields on the UKCS, but a more united approach is needed.

Neil Poxon, Industry Technology Facilitator (ITF)

lastWORD

A country-wide strategy for

new technology is required to get

the remainingreserves out of

the ground.

LastWord_LastWord 3/23/11 5:02 PM


TETRACOMPLETION FLUIDS &

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because every Well is unique.

FLUIDS TECHNOLOGY, EXPERIENCE, AND EXPERTISE FOR MONITORING THE DISPLACEMENT PROCESS

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By contra and moni istry of our products from manuring to placement inthe well 4IETRA's u r j to produce fluids especially for our customers' well conditions,while maintaining fluid integrity, sets us apart from our competitors.

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PLETION FLUIDMANAGEMENT SERVICES

COMPLETE FLUID SYSTEM DESIGN¦ MatchWell ® 13Cr Tubing/Packer

Fluid Compatibility Analysis¦ Custom Clear Brine Fluid

(CBF) Blending

WELL SITE SUPERVISIONPLANNING I EXECUTION I EVALUATION¦ Deep Design® Displacement Desi gn

& Modeling¦ AdvanceClean® Wellbore Displacement

& Casing Clean Up¦ SafeDEf lo® & OilFix"Filtration Services¦ Completions Archive

2011 TETRA' Technologies, Inc. All Rig hts Reserved . 281.367.1983TETRA, the TETRA logo, MatchWell, Deep Design , AdvanceClean, and SafeDEflo are so les @ t e t r a t e c .c um

111registered trademarks , and OilFix is a trademark of TETRA Technologies, Inc.

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Po erDrive ArcherHIGH BUILD RATE RSS

"The PowerDrive Archer tool is a definite game-changing technology that will dramatically improve drilling efficiencies."-William "Bill" Lloyd, Cirque Resources , VP Operations , North America.

PowerDrive Archer is the RSS that delivers high build rate well profiles previously onlypossible with motors-yet with the ROP and wellbore quality of a fully rotating RSS.

www.slb .com/Archer

Global Expertise I Innovative Technology I Measurable Impact

Schiumberger

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