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F E B R U A R Y 2 0 1 3

UNDER PRESSURE

E P M A G . C O M

HYDRAULICFRACTURING

New methodologies prop open more

opportunities

Reservoir Characterization

Wellhead PadDesign/Equipment

Subsea ProcessingAdvances

Enhanced Recovery

Drill Bit Technology

REGIONALREPORT:South America

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OpportunitiesIf you have a thirst for creativity, are passionate aboutdriving your own career and dream of working with asuccessful oil and gas exploration and production company,Cimarex is the place for you. We're looking for top talent in avariety of disciplines:

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Microbial EOR makes gains

Enhancing production with new gas lift valve

Rhamnolipid biosurfactants: new technologyfor EOR, remediation

RESERVOIR CHARACTERIZATION

Appraising ultra-deepwater reserves

Evaluating reservoirs with a sharper focus

DRILL BIT TECHNOLOGY

Advancing hard/harsh rock drill bits

Drill bit designed to return microcore samplesto surface

PDC drill bit innovations drive performance inchallenging zones

WELLHEAD PAD DESIGN/EQUIPMENT

Economical solutions meet state and federalmandates for gas flaring

Four-for-one well pad design leaves a smallerfootprint behind

SUBSEA PROCESSING ADVANCES

Planning for the future

Seabed production innovation boostsexpectations

IndustryPULSE:The future of natural gasGas prices suffer from a lack of demandcoupled with negative public opinion.

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

FEBRUARY 2013VOLUME 86 ISSUE 2

A HART ENERGY PUBLICATION www.EPmag.com

38

By using alternatives to freshwater, operators find opportunities for success that can help change public perception during times of drought.

8

WorldVIEW: First in classChristopher J. Wiernicki, ABS president

and CEO, talks about the changing role of class,the need for agility in a rapidly advancing industry,and the value of partnering to extend the reach ofoffshore oil and gas operations.

12

Unconventional: Unlocking IndonesiasCBM potentialWith its estimated CBM reserves ranking it

No. 6 in the world, this slumbering Southeast Asian con-ventional oil and gas giant is picking up the develop-ment pace of its unconventional resources.

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104

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46Proppant economics in the Eagle Ford formation52

Hydraulic fracturing: new perspective leads to successes

REGIONAL REPORT:SOUTH AMERICA122

COVER STORY: FRACTURING

Optimized treatment design shows promise

01-6 TOC-FEB_TOC 1/18/13 11:19 AM Page 1

01-6 TOC-FEB_01-6 TOC-FEB 1/17/13 8:42 PM Page 2 01-6 TOC-FEB_01-6 TOC-FEB 1/17/13 8:42 PM Page 3

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February 25-27, 2013Calgary, AB, CanadaTELUS Convention Centre

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DUG Australia brings market-leading insight on unconven-tional gas from coal-seams , shale and tight sands nowbeing developed in Australia and the Asia-Pacific region.Topics include potential resources, project capitalizationand best drilling and completion practices.

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MANAGEMENT REPORTMinimizing risk in A&D 16

DIGITAL OIL FIELDRemote automation and monitoring captures Caspian value 20GPU usage grows in digital oil field 24

EXPLORATION TECHNOLOGYFlying high to find reservoirs 31

DRILLING AND COMPLETION Water depth, availability drive use of jackup in Chukchi Sea 33

PRODUCTION OPTIMIZATIONChasing the rabbits of public opinion 35

OFFSHORE ADVANCESSafeguarding the right to operate 37

INDUSTRY IMPACT Automated sources, streamers improve seismic repeatability 115

TECH WATCH Fracturing with field gas 116

TECH TRENDS 120INTERNATIONAL HIGHLIGHTS 126ON THE MOVE/INDEX TO ADVERTISERS 129-131

LAST WORD Responding to the challenge of induced seismicity 132

E&P (ISSN 1527-4063) (PM40036185) is published monthly by Hart Energy Publishing, LP, 1616 S. Voss Road, Suite 1000, Houston,Texas 77057. Periodicals postage paid at Houston, TX, and additional mailing offices. Subscription rates: 1 year (12 issues), US $149; 2 years (24 issues), US $279. Single copies are US $18 (prepayment required). Advertising rates furnished upon request. POSTMASTER:Send address changes to E&P, PO Box 5020, Brentwood, TN 37024. Address all non-subscriber correspondence to E&P, 1616 S. VossRoad, Suite 1000, Houston, Texas 77057; Telephone: 713-260-6442. All subscriber inquiries should be addressed to E&P, 1616 S. Voss Road, Suite 1000, Houston, TX 77057; Telephone: 713-260-6442 Fax: 713-840-1449; [email protected]. Copyright Hart Energy Publishing, LP, 2013. Hart Energy Publishing, LP reserves all rights to editorial matter in this magazine. No article may bereproduced or transmitted in whole or in parts by any means without written permission of the publisher, excepting that permission to photocopy is granted to users registered with Copyright Clearance Center/0164-8322/91 $3/$2. Indexed by Applied Science, TechnologyIndex and Engineering Index Inc. Federal copyright law prohibits unauthorized reproduction by any means and imposes fines of up to$25,000 for violations.

DEPARTMENTS AND COMMENTARY

ABOUT THE COVER Despite the controversy, hydraulic fracturingcontinues to open up new reserves of oil and gas. Left, Uruguay is one ofseveral South American countries poised to enter the global energy arena.(Photo courtesy of Schlumberger; cover design by Laura J. Williams)

COMING NEXT MONTH The March issue of E&P takes a deep-down look at downhole tools and technology. Other features include intelligent operations, 4-D seismic,drilling fluids, artificial lift, and floating production, and E&Ps annual Drill Bit Records reportwill highlight the latest drilling breakthroughs. Regional highlights include the frenzied activity in the Bakken shale and an overview of operations in Azerbaijan and Kazakhstan.As always, while youre waiting for the next copy of E&P, remember to visit EPMag.com fornews, industry updates, and unique industry analysis.

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Cuadrilla gears up for UK fracing By Steven Hamlen, Special to E&PThe UK government gave the thumbs up to fracing in the country with new controls aroundseismic risk.

Nigeria falls behind in worlds LNG race, projects delayed By Obafemi Oredein, Special to E&PExperts say there is potentially up to 600 Tcf of gas still to be found in thecountry.

Coal could edge oil as top energy source By Darren Barbee, Hart Energy

Though an abundance of shale gas leads toless coal consumption in the US, the use of coal

remains prevalent in countries in other parts of the world.

Independents make exploration strides in frontier basins By Velda Addison, Associate Online Editor

National oil companiesremain in an infancy

stage when it comes to international explo-ration, but change could be coming, accord-ing to Wood Mackenzie.

Eni and Anadarko sign HOA to develop natural gas reservoirs in Mozambique Eni has signed a heads of agreement (HOA) with Anadarko PetroleumCorp. establishing foundational principles for the coordinated devel-opment of common natural gas reservoirs offshore Mozambique, thecompany said.

Endeavour mobilizes semisub to Rochelle field Endeavour International Corp. has mobilized the Transocean Prospectsemisubmersible rig to complete drilling in the Rochelle field in the central UK North Sea, the company said in a press release.

Delineation well expands Indra discovery for Petrobras offshore Brazil A delineation well on the ultra-deepwater Indra discovery in the post-salt Espirito Santo basin offshore Brazil has confirmed the presence of light oil and gas in sandstone reservoirs, according to a press releasefrom Petrobras.

READ THELATESTEPmag.comINDUSTRY NEWS


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Get ready to innovateSometimes the best ideas come from the strangest places.

The oil and gas industry cannot thrive without technology, and technologycannot be developed without innovation. But what, exactly, is innovation?Peter Diamandis, chairman and CEO of the X PRIZE Foundation, has grap-

pled with this concept since his dream of becoming an astronaut was stalledwhen the US abandoned its manned space flight program in the 1970s. Hedecided to investigate the idea of private space flight.

The idea was to have innovation be driven by competition, Diamandis tolda gathering at the recent Shell Innovation Summit. He proposed a competi-tion that would award US $10 million to a team that could build a spacecraftthat could carry three adults into space.

It took Diamandis six years to raise the money, but in the end 26 teams competed.

This approach differs from normal R&D, he said, because it incentivizesnontraditional players to innovate. We look at where there are market fail-ures, he said.

What Diamandis considers a market failure would be considered by mostothers to be a serious global issue. Some of the recent X PRIZE challengeshave included developing a car that gets 161 km (100 miles) to the gallon, ahandheld device that can diagnose a patient as accurately as a team of special-ists, and a map of the ocean floors.

One recent challenge was to double the rate at which an oil spill can becleaned up from a body of water. More than 300 teams signed on for the ini-tial competition; this was later narrowed to 10. Seven of the 10 teams managedto double the rate, and the winning team increased the cleanup time 600-fold.

One team met in a tattoo parlor in Las Vegas, Diamandis said. Some ofthese people come from very unusual places.

So what is it that drives X PRIZE winners to innovate? The $10 million prizeis no doubt a significant motivator. But Diamandis thinks there is more to itthan greed.

Its tied to passion, to trying to make a difference, he said. Everythingthat fuels these people comes from their hearts and souls. By the time theymake a breakthrough, they will have been told no a thou-sand times.

Innovation requires absolute persistence, headded. Everything is impossible until you makeit happen.

As ISEE IT

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

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

7

Read more commentary atEPmag.com

RHONDA DUEY Executive [email protected]

Executive Editor RHONDA DUEY

Group Managing Editor JO ANN DAVY

Senior Editor, Drilling SCOTT WEEDEN

Senior Editor, Offshore MARK THOMAS

Senior Editor, Production JENNIFER PRESLEY

Chief Technical Director, Upstream RICHARD MASON

Associate Managing Editor MARY HOGAN

Associate Online Editor VELDA ADDISON

Assistant Editor CODY ZCAN

Corporate Art Director ALEXA SANDERS

Senior Graphic Designer LAURA J. WILLIAMS

Production Director JO LYNNE POOL

Reprint & PDF Sales ERIC MCINTOSH

Director of Business Development ERIC ROTH

Group Publisher RUSSELL LAAS

Editorial Advisory Board

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

KEVIN BRADYPresident, Multi Products Company

MIKE FORRESTExploration Consultant, formerly with Shell

JOHN M. GILMORE JR.Director of Global Industry Solutions Upstream Oil & Gas, Invensys Operations Management

CHRIS JOHNSTONVP & Managing Director, North America, Ensco

ULISSES T. MELLOManager, Petroleum & Energy Analytics, IBM

DONALD PAULExecutive Director, University of

Southern California Energy Institute

EVE SPRUNTBusiness Development Manager, Chevron Energy Technology Co.

MANUEL TERRANOVASr. VP Regional Operations & Global Sales,

Drilling & Production, GE Oil & Gas

RONNIE WITHERSPOONPresident,

Superior Well Services, a Nabors company

DENNIS A. YANCHAKSr. Geosciences Advisor, Apache Corp.

Editorial Director PEGGY WILLIAMS

President & Chief Operating OfficerKEVIN F. HIGGINS

Chief Executive OfficerRICHARD A. EICHLER

07 AsISeeIt-FEB_07 AsISeeIt-FEB 1/17/13 8:42 PM Page 7

EP

H A R T E N E R G Y

The future of natural gas is a hard thing to predict.Commodity forecasting is a pseudo-science at best. At times it seems that its primary function is to makeastrology look respectable.

The US has enormous natural gas resources, arguably a100-year supply. Will that resource be the low-cost, low-pol-lution energy source that provides America with a bettereconomic and environmental future, or will it remain inthe ground? What will decide this question?

There is no more powerful force for change than themarket. But commodity markets do not care about politi-cal correctness. These markets only care about supply anddemand. And right now natural gas is on the wrong sideof that equation.

In March 2012 increased production drove Lower 48 gasstorage to 2.4 Tcf, almost 0.9 Tcf above the five-year seasonalaverage. That was the largest seasonal glut since the EnergyInformation Agency (EIA) started keeping records in 1994.The warmest winter since 2000 plus abundant shale gassoon forced US natural gas wellhead prices below US$2/Mcf, the lowest level in 13 years. By comparison, Euro-peans currently pay almost $12/Mcf for imported naturalgas. The US has been blessed with huge shale gas resources.Shale gas may be predictable, but it is not cheap. At pricesmuch below $4, these resources will not be aggressivelydeveloped. Commodity reserves are and always will be afunction of price. At the European price of $12/Mcf, wewould all be shocked and amazed at how much gas the US

has. Perhaps exports will drive development and price, but we will have to wait and see how the politics play out.

History indicates that natural gas resources will not getconsistently developed. Boom-and-bust cycles will likelycontinue. Gas producers will pour money into drillingwells when prices spike, which too often will create thenext bust. Unfortunately, those same price spikes discour-age long-term commitments to gas by large-volume utilityand industrial consumers.

Maybe these lessons can benefit both producers and con-sumers. But first some data-driven analysis is needed to bet-ter understand the natural gas market: what is currentlyhappening as well as what may happen down the road.

ElectricityElectricity is the biggest slice of the demand side and alsothe slice with the greatest upside for increased gas con-sumption. In January 2011 coal was the fuel of choice for48% of electricity generation, while natural gas accountedfor about 20%. But as prices plummeted by April 2012, gaswas generating as much electricity as coal.

Unfortunately for coal, the EPA recently set tough limitson CO2 emissions for new electricity plants. Without car-bon capture and storage (CCS), coal is no longer anoption for new plants. Clean coal cannot happen withoutCCS, and no coal CCS facility has ever been built in theUS. However, the greatest challenge for CCS is not techni-cal; it is economic. The numbers just do not make sense.

A 2008 McKinsey report, Carbon Capture and Storage:Assessing the Economics, estimated that if about 100 CCSprojects were built by 2030, the cost of removing 90% ofthe CO2 produced from new coal plants might fall tosomewhere between $37/ton to $55/ton of CO2. Earlyplants would cost at least twice that much. And combiningoxygen atoms with coal produces about two tons of CO2per ton of coal burned.

For reference, US utilities paid about $45/ton for coalin 2012. Burning clean coal would roughly triple that fuelcost. But the story gets even worse. Due to carbon captureenergy demands, utilities would have to burn 25% morecoal just to produce the same number of kilowatts. Andonly a handful of Americas most modern coal-fired plantscould potentially be retrofitted with CCS.

Coals greatest asset as a fuel is the number of older,paid-off coal plants. But those plants also produce the

Utilities have an incentive to switch to natural gas

over coal due to environmental regulations,

but owners are not comfortable with the

volatility of the natural gas market.

February 2013 | EPmag.com8

industryPULSE

The future of natural gasGas prices suffer from a lack of demand coupled with negative public opinion.

Rutt Bridges, former SEG president

08-11 IndPULSE-FEB_08-11 IndPULSE-FEB 1/17/13 8:42 PM Page 8

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most pollution and are likely to continue to be shut downto meet increasingly strict pollution standards.

The real issue is not what the plant costs but what theelectricity costs. The short version is that electricity fromnew natural gas plants costs about half as much per kilowattas new coal plants, and those EIA estimates are at gas pricesof $4.78/Mcf. The other big electricity source is nuclear.The only two new US nuclear plants to be built since 1979(remember Three Mile Island?) were both initiated whengas prices were approaching $11/Mcf. Both are well overbudget and far behind schedule, and there is about $1 bil-lion in utility vs. construction vendor lawsuits pending.

Economics is what drives utilities to decide what kind offuel to burn and what kind of plants to build. More andmore, natural gas has been winning that competition. Fornew plants not only does gas produce cheaper electricity,but the capital costs are lower, construction is faster, andnew capacity can be built closer to where it is needed.There are far fewer not in my backyard objections, sosmaller modular gas-fired plants can be located nearerconsumers and power grids. Plus, pollutants are a smallfraction of those from coal plants, and gas plant CO2 emis-sions are about 37% of coal per kilowatt, already meetingnew EPA standards.

On the negative side, if gas prices spike, utilities arestuck burning gas. And that market risk is the greatestimpediment to long-term natural gas demand.

Recent low gas prices have kept the more efficient gasplants running nearly flat out. Stricter pollution regula-tion has also benefited gas, and the increased use of gashas been a major factor in a 14% drop in US CO2 emis-sions since 2007. Gas has been a favorite alongside inter-mittent wind and solar since plants can start up and shutdown in about 30 minutes and also can run at variablepower levels. It is impossible to do a quick startup or shut-down of a coal or nuclear plant.

Since 2001 and especially in the past year there has beena dramatic decrease in the use of coal and a dramaticincrease in the use of gas. Once again, the market is a pow-erful force. Here is what the US electricity market lookslike right now, and here is where it appears to be headed:

Coal will continue to shrink due to cost and pollutionissues (but export markets are strong);

Gas has major market and environmental advantagesand should continue to grow if we can mitigate pricespikes and better address public concerns about fracing;

Delays and cost overruns for the two new US nuclearplants will hurt prospects for growth;

Hydropower lacks good sites for new dams and has lit-tle growth potential;

Wind and solar are heavily dependent on unpre-dictable subsidies to consistently grow; and

Everything else is too small to matter unless enhancedgeothermal can greatly reduce costs.

Pitfalls in the road aheadThere is a lot of opportunity for natural gas to continue toexpand its market in electricity generation and potentiallyin exports. Shale gas has been a game-changer for the sup-ply side, but we need growth on the demand side. Whatare the pitfalls in the road ahead?

No matter how unfair it may seem, fracing has a bad rep-utation with far too many Americans. There is a rule ofthumb in the media that if it bleeds, it leads. The David-and-Goliath battle of local landowners and environmental-ists vs. big oil and gas comes close enough.

Both sides are approaching the fight in very differentways. The industry feels that it has logic and reason on itsside, but the storyline may be a bit technical for mostfolks: Fracing takes place deep in the earth, with thou-sands of feet of solid rock between the fracing and yourwater supply. The fractures only affect a small part of thedeepest rocks, and steel casing and cement in the well pro-tect the aquifers.

That does not exactly tug at folks hearts like a familywhose water has gone bad. Unfortunately, one anecdotecan have more influence than a thousand statistics. Whileit is true that the fracing of the rocks has never caused aproblem, in a few cases the cement job around the casingthat protects aquifers has failed. Such examples are rare,and companies have almost always been quick to respond.But so has the media. A few accidents translate into a lotof newsprint and 30-second TV spots.

Progressive gas developers have worked with states totighten well completion standards, which were typicallyestablished long before shale gas fracing was common.Many companies voluntarily disclose fracing fluids on

EPmag.com | February 2013 9

Operators can show simplistic

images of their fracing opera-

tions, but the public also is being

bombarded with images such as

the burning faucet in Gasland.

industryPULSE



public websites. Several states already require disclosure,and more will follow. But as long as a few companies areunwilling to disclose, the issue will remain in peoplesminds. Every time the industry argues that 99% of frac fluids are sand and water, the public immediately thinksabout that other 1%. Who will the public believe?

Opponents to fracing have often taken a visual approach.In the movie Gasland, millions of Americans saw flamesshooting out of a faucet. That anecdotal evidence leaves a powerful impression, especially compared to our moretechnical arguments, even if it is false and misleading.

Due to public concerns, the Colorado Oil and Gas Conservation Commission tested the methane from thisburning faucet. Scientific analysis proved that the flaminggas was biogenic in origin as opposed to the thermogenicgas that comes from deep shale gas deposits. Unfortu-nately, the average homeowner does not understand ormuch care about the difference between shallow biogenicand deep thermogenic gas. They just remember the flam-ing faucet.

Wars seldom determine who is right, just who is left. Wehave a lot at stake. But if both sides are willing to sit downand truly listen to each other, it is sometimes possible tofind a compromise that works reasonably well for every-one. Sometimes you can find a 60:60 deal, where bothsides working together get more out of the compromisethan they would if they treat their differences as a win-losebattle. This is true for gas producers and utilities as well asgas producers and fracing opponents. The compromisesmay not be perfect for both sides, but can we afford to letthe perfect be the assassin of the good?

I know many people in our industry who care deeplyabout the benefits that natural gas can bring to Americaand to the world. Environment and economic prosperitycan coexist. But if you want to catch a trout, you have to bewilling to sacrifice a fly. Unless both sides can find reason-able compromises to our differences, we will waste far toomuch of our lives and far too much of our treasure wagingwar. Worse still, we may all lose out on this potentiallytransformational opportunity in American history.

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The new Bartell Geology and Geophysics Field Camp in the Colorado mountains provides students of the ConocoPhillipsSchool of Geology and Geophysics with a chance to acquire real-world f ield experience in the summer.

ere at the beginning. Here for the future.The ConocoPhillips School of Geology and Geophysics (CPSGG), part ofthe Mewbourne School of Earth and Energy at the University of Oklahoma,has been a leader in Geological Sciences for over a century.

Founded by Charles Gould in 1900, OU's geology and geophysicsprogram granted the world's first degree of Petroleum Geology in 1904.OU was the site of the American Association of Petroleum Geologists'inaugural meeting in 1916.

OU alum J. Clarence Karcher conducted the first reflection seismographsurvey in 1921 in Oklahoma City and partnered with OU alum EverettLee DeGolyer to form Geophysical Research Corporation, America'sfirst seismic company.OU has graduated more petroleum geologists than any program in theworld-over 5,000 and counting.

MEWBOURNECOLLEGE OF EARTH&ENERG'

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Real education for the real world.

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First in classChristopher J. Wiernicki, ABS president and CEO, talks about the changing role of class, theneed for agility in a rapidly advancing industry, and the value of partnering to extend thereach of offshore oil and gas operations.

The role of class has evolved as the offshore industryhas advanced into deeper water and more exactingoperating environments. As E&P activities move intoeven more challenging frontiers, ABS President andCEO Chris Wiernicki explained how class continues totransform to answer the industrys changing needs.

What is ABS role as a class society?The foundation of class is safety. Whatever role classplays, you cant ignore that. Everything ABS does has tobe true to our mission to promote the security of lifeand property and to preserve the natural environment.

Initially, oil and gas industry players wanted a class cer-tificate for insurance purposes and proof of compliancewith international regulatory requirements. Today theindustry is taking advantage of the certification process byincorporating it more fully into maintenance programs toimprove asset and equipment reliability and by seekingapproval in principle for new technologies required tosupport boundary-pushing projects.

Operating companies and drilling contractors are look-ing for ways to advance safely into operational frontiers, toincrease uptime, to improve productivity, and to extendthe life of offshore assets. Because we work with oil servicecompanies, drilling contractors, and operating companies,we are able to provide greater confidence in the safety ofequipment and assets across the board.

Were always looking at ways to refine and reshapeclass. To do that, we have to be proactive working withthe industry to develop safety standards, finding prag-matic approaches to safety in new and challenging envi-ronments, and advancing solutions that allow safe andefficient operations. This is essential to maintaining theconfidence of the industry and to ensuring that the roleof class keeps pace with industry needs.

What differentiates ABS as a class society?Only a handful of class societies have experience withoffshore classification, so the question becomes, Howdoes ABS differentiate itself within this group?

We have been successful for the last 60 years by help-ing the industry take on new and challenging situations.ABS was the first society to class an offshore unit, whichrequired us to develop a set of safety requirements usingour marine experience and engineering judgment foran application never seen before.

We are a technology-driven organization. My back-ground and training are in engineering, so the personat the helm of ABS understands the importance of tech-nology development and the role technology plays indecision-making.

I believe the ability to apply core engineering andtechnological knowledge along with our experience willcontinue to be a key differentiator in developing practi-cal innovative solutions that help the offshore industrymove forward.

Another significant difference is that we know the off-shore industry is different from the marine classificationbusiness. We have a separate Offshore Technical Com-mittee made up of industry experts to provide guidanceon rule development specifically for the offshore oil and

Christopher J. Wiernicki, ABS president and CEO. (Images

courtesy of ABS)

J. Massimo, Contributing Editor

worldVIEW

12-15 WorldView-FEB_12-15 WorldView-FEB 1/17/13 8:42 PM Page 12

12-15 WorldView-FEB_12-15 WorldView-FEB 1/17/13 8:42 PM Page 13

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gas industry. And we have organized our technologygroup to create a specific offshore-focused team.

Frankly, though, I think the key differentiator is ourpeople. ABS employees are passionate about what theydo, and they understand the value of safety and how thethings they do touch their clients.

How is ABS working with offshore players?As I mentioned earlier, ABS classed the first offshore unit.And we have been involved in every single barrier-break-ing technology in the industry since that time. We classedthe first jackup, semisubmersible, drillship, FPSO, tension-leg platform, and spar.

Im proud of our history, but Im equally proud of howwe are working globally on pioneering projects.

Part of our edge is that we realize that although a lot ofR&D goes on in Houston, not everything is US-centric. Werecognized several years ago that developing technologycenters in dynamic areas around the world would allow usto carry out R&D efforts closer to our clients. Today ABShas R&D facilities in Singapore, Brazil, Korea, and China.

What is in the future for class societies?While the future is uncertain, one thing cant change.Class societies cant lose their focus on safety. That is non-negotiable. The other thing they have to retain is theirindependence. The value of a class society is its uniqueposition in the industry as an independent broker ofsafety. We must never lose sight of the fact that we trade onintegrity and must earn the trust of the industry every day.

Safety is a responsibility, not a business. It should never befor sale. And to be effective, safety has to be implementedimpartially and objectively. ABS has no shareholders orowners, so we offer a truly independent, unbiased view.

When I think about the class of the future, I always lookback to ABS first foray into the offshore, classing an off-shore unit in the absence of established requirements. Wehad to develop groundbreaking guidelines and rules. Wehave to continue to be groundbreaking if were going tosupport the offshore industry in the future. Owners andoperators want to improve efficiencies, increase produc-tion, and minimize downtime. Part of our job is to helpthem do those things safely.

Thats why we are developing tools like the Independ-ent Software Quality Management (ISQM) system. ISQMreduces commissioning time for newbuilds and provides aframework for coordinating and controlling softwaredevelopment, integration, and maintenance. It is anexample of how ABS has evolved in response to industryneeds to address the next generation of safety systems.

Our clients expect this. They rely on us to assist them insolving tough problems that allow them to maintain thehighest safety standards without disrupting operations.

Last year we updated our drilling systems certificationrequirements to make sure these are suitably robust, andwe worked closely with industry to develop the next gener-ation of safety standards for well control equipment. Wealso participated in several BOP safety improvement andreliability programs with US and Norwegian regulatorsand industry groups.

ABS ability to respond quickly and to meet industryneeds has earned us a formidable position today andplaces us firmly where we need to be to play a leading roletomorrow. Our continued goal is to work with industry tobreak down the technology barriers that constrain thescope and extent of offshore operations.

worldVIEW

ABS classed the first mobile offshore drilling unit in 1958 (top),

the first production spar in 1996 (middle), and the largest pro-

duction semisubmersible in 2007 (bottom), among many other

breakthroughs.

12-15 WorldView-FEB_Layout 1 1/18/13 10:27 AM Page 14

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Energy commodities have a proven history of suddenand significant commodity price declines and theremight be no worse time for a steep drop than when a com-pany is trying to do an acquisition.

A company that signs an agreement to purchase anenergy asset typically commits to paying a fixed price. Butthe purchased assets value can float with the underlyingcommoditys forward price curve in that 30- to 45-dayperiod before the acquisitions close. E&P master limitedpartnership (MLP) enterprises seeking to grow throughacquisition face the dilemma of commodity price fluctua-tion eroding, or even wiping out, the financial benefits ofthe deal.

It does not have to be that way, though. Smart use ofhedging techniques can minimize or eliminate the risk.And the hedging can start when the papers are signed,even before the assets are formally purchased.

First, lets illustrate the kind of price move that canjeopardize a deal. Figure 1 shows the forward three-yearWest Texas Intermediate (WTI) crude oil curve over a 45-day period in spring 2012. Assume a company (we willcall it BuyCo) had priced a transaction in mid-April with

the three-year strip at US $99.85. By the time the dealclosed at the end of May, the three-year curve haddeclined by $17.98, or 18%, to $81.87. This would affectthe deal economics and ultimately the payout at somefuture liquidation event. In the MLP world, it couldrestrict the ability to pay the distributions needed toremain attractive to investors.

OptionsPut options are the building blocks for hedge transactionsthat do not create exposure. A put option is a contractbetween two parties to exchange an asset (the underlying)at a specified price (the strike) by a predetermined date(the expiry). One party, the buyer of the put, has theright, but not an obligation, to sell the asset at the strikeprice by the future date, while the other party, the seller of the put, has the obligation to buy the asset at the strikeprice if the buyer exercises the option. The buyer of theput option pays a premium to the seller.

In our view, producers tend to overpay for put options. A purchased put protects the producer in the unlikelyevent that prices fall to zero. But our analysts believe thatprices below $65 are not sustainable in the long term sinceunconventional oil projects become unprofitable. There-fore, price protection below $65 has marginal utility, espe-cially if the bank price deck is at or above this level. Aproducer is better off selling off protection below $65 via a put spread.

The put spread is the combination of a long put optionand a short put option at different strike prices for thesame time period. The cost of a put spread is lower than aput option because the producer collects a premium forthe sold put option.

The put swaption is an option granting its owner theright but not the obligation to sell an underlyingswap at a specified price. It also requires the buyer to pay a premium to the seller. Put swaptions exercise into swaps if the market price at expiration is below the strike price. If the market is above the put swaptionstrike price, the producer would not exercise and is freeto hedge. If the acquisition has not closed at the exercisedate, then the put swaption will cash-settle, and the pro-ducer remains unhedged. The expiration date of a putswaption should be set a few weeks after the closing dateto account for minor delays in closing.

Minimizing risk in A&DAn optimal combination of hedging tools needs to consider market view, curve structure volatility, and option skew so that producers can get the most price protection for the least cost.

Bob Deman, Asset Risk Management LLC

managementREPORT

WTI Cal 13-15 Forward Price Curve

Three-year Forward Strip Daily SettleHigh = $99.85Low = $81.87

$110

$105

$100

$95

$90

$85

$80

$75

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March-2012 April-2012 May-2012 June-2012 July-2012

Almost an $18 decline in value

Shown is the forward three-year WTI crude oil curve over a 45-day

period in spring 2012, illustrating how price movements can jeop-

ardize a deal. (Image courtesy of Asset Risk Management LLC)

16-19 MgtReport-FEB_16-19 MgtReport-FEB 1/17/13 8:43 PM Page 16


Now, how can hypothetical BuyCo use the hedging toolsto protect itself? Lets look at options that require anupfront cash outlay as well as options that require nomoney down.

Paying to hedge before the closeIf BuyCo has the free cash, it can purchase a combinationof puts, put spreads, or put swaptions to hedge 100% ofthe price risk. Pricing changes in the energy markets canmake it easy to overspend for price protection or choosethe wrong structure. For instance, in a low-volatility envi-ronment, puts or put swaptions may be superior to putspreads in cost effectiveness. A market in steep backwarda-tion (future prices far below the current spot price) is notthe best environment to use swaps or put swaptions.

After the acquisition closes, BuyCo can attempt torecoup its hedging costs. It can sell call options to convertnew put positions into collars or put spread positions intoproducer three-ways. It also can turn swaps into protectivespreads by selling puts against the swaps that were created

through exercise of the put swaptions. These techniquescould allow BuyCo to collect all or even more than theoriginal hedging costs.

The puts, spreads, and swaptions could cost a significantamount of money, however. Alternatively, BuyCo canhedge with swaps and post a margin, a technique thatcould significantly reduce out-of-pocket costs. Margin isthe collateral a bank needs to offset the risk and exposurecreated when the bank transacts with a producer that hasnot pledged assets.

After the acquisition closes, the acquisition assets securethe margined swaps, and BuyCo returns the posted mar-gin. The big risk with cash margining is cash availabilityshould the market explosively move higher before theclose. For example, a 1,000 bo/d short WTI swap for threeyears would incur $1.095 million in margin for every $1that WTI moved higher.

Cash-free hedgingWhat if BuyCo does not have enough cash on hand to

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purchase price protection for the acquisition? First,assuming BuyCo already has assets, it could use its sparehedge capacity or restructure existing hedges. To usespare hedge capacity, BuyCo will have to hedge to thefullest extent allowed by the covenant in its credit facility.

The second method is restructuring the existing hedgeportfolio. Assume BuyCo has an existing 100 b/d Cal 14WTI producer collar in place a long $85 put and a short$105 call. BuyCo can buy back the existing short $105 calland defer the premium payment until 2014.

Alternatively, BuyCo can extract value by rolling theputs and/or calls. Lower put strikes are cheaper, so BuyCocan receive a premium payment by selling the existinglong $85 put and buying a $75 strike. And since lower callstrikes are more expensive, BuyCo could get another pre-mium payment by buying the $105 call back and selling a$95 call to replace it. BuyCo can invest the premiums innew hedges covering acquisition volumes.

The third method looks to the seller. If the seller hashedges, it can be included as part of the acquisition, lock-

ing in hedge economics. The acquisition sales price is sim-ply adjusted up or down based on the mark-to-market ofthe hedges at the signing of the production sharing agree-ment. It is possible to avoid costs for transferring thehedges, especially if the buyer and seller have a commonbank for their credit facilities.

Regardless of the strategy, producers need to look deepinto the market to ensure they get the most hedge cover-age for the cheapest possible price. Hedging is an art, nota science. The optimal combination of puts, put spreads,and put swaptions should be created with careful attentionto market view, curve structure volatility, and option skewso that the producer can get the most price protection forthe least cost. Most importantly, producers should treattheir hedges like assets and manage them much as theywould manage the assets bought in a deal.

AcknowledgmentThis article originally appeared in the October 2012 issue of Oiland Gas Investor.

managementREPORT


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Function-testing safety valves like emergency shutdownvalves (ESDV) or blowdown valves (BDV) is a signifi-cant job, and a key element for consideration is the traveltime the time that an ESDV takes to close or a BDV toopen. Measuring safety valve travel time requires the oper-ation of these critical devices, normally resulting in a par-tial plant shutdown with inevitable consequences on theproduction profile.

BP introduced its Safety Valve Travel Timer (SVTT) software at Sangachal Terminal in Azerbaijan, and afterearly successes it was further deployed offshore in theAzerbaijan-Georgia-Turkey (AGT) region.

The tool, developed and supported within BPs Field of the Future program, automates travel time data acquisi-tion and is designed to continuously monitor the operationand movement of ESDVs and BDVs. It calculates the timefor a valve to transition from one state to another and com-pares this against the target time for showing results. Thedata are automatically collected during both routine andunplanned activities.

Deployment of the SVTT software helps reduce thenumber of function tests carried out on safety valves,thereby delivering significant cost savings. Moreover, theautomated monitoring of safety valves allows proactiveintervention on abnormal valve performance before failures occur.

Monitoring 1,841 valvesThe onshore implementation of the SVTT covers 438valves (356 ESDVs, 66 BDVs, and 16 flare valves) located atthe Sangachal Terminal. Offshore, the SVTT was config-ured on 1,403 valves comprising 90 BDVs and 1,313ESDVs a combined total of 1,841 valves in the region.

The offshore implementation includes some subsea treevalves, but the monitoring focus and priority are on top-side process safety valves. In the SVTT monthly report tothe assets, valves are prioritized based on their safetyintegrity level (SIL) and environmental integrity level

(EIL) rating, with particular attention given to valves withSIL/EIL 1 and above.

For wellhead-related valves, continuous monitoringpresents a more marginal value opportunity because thesevalves undergo twice-yearly well integrity tests (WIT),which include pressure buildup test requirements. How-ever, for these valves the SVTT offers continuous loggingof valve movement that can track performance, especiallywhen integrated with WIT results.

Travel time was configured using process safety hazardmanagement measures documents, which included the valves performance standards. Data were criticallyreviewed and compared with the information found onthe specific safety requirement specification and valvesmanufacturer data sheet. For the majority of valves, themost interesting target is the limit-to-limit time. Depend-ing on the valve body size and application, the target timesvary from 1 to 2 seconds up to 30 to 35 seconds.

The deployment of the SVTT software has been accom-panied by a rigorous business process. A single point ofaccountability (SPA) was appointed to own the applica-tion in the region and liaise with all the relevant stake-holders within the company, including the Field of theFuture development and deployment teams, instrumenta-

digitalOIL FIELD

Remote automation and monitoringcaptures Caspian value The reliable operation and monitoring of safety critical valves are vital to the oil and gas industry. Their failure to operate on demand could have catastrophic consequences.

Luca Marinai, Ajay Khetarpal, Brett Grange, George Mackinnon, and Christopher Houghton, BP

BPs SVTT system has helped to reduce by half outages needed

for routine periodic function testing of critical safety valves.

(Images courtesy of BP)

20-23 DOF-BP_20-23 DOF-BP 1/17/13 8:43 PM Page 20


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Bluebeamm Revu enables you to work smarter and -faster, without compromise. Improve projectdocumentation by digitally reviewing P&IDs using colored symbols to indicate open and closedvalves, sequence annotations to automatically number valves, highlights to trace isolation boundarylines, and electronic stamps to sign off on documents. Save custom markups in the Tool Chest TIA foreasy reuse, and export custom tool sets to share with colleagues. All annotations are automaticallytracked in the Markups list, which can be imported into Excel to quickly and easily create checklistfor test packs. Collaborate securely on the same P&IDs in real time with onshore and offshoreteams using Revu's cloud-based solution, Bluebeam Studio'TM, on a desktop, tablet PC or iPad.

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tion and control technical authori-ties, asset maintenance staff at mul-tiple assets in the regions, and stafffrom other BP regions to sharelearnings and experience. The SPA prepares a monthly report for each asset in the region, provid-ing routine valve movements track-ing and data analysis.

Data and resultsIn the Caspian region safety valvehealth has been monitored on acontinual basis with the SVTT soft-ware. The ones that fail to operateon demand or do not move in pre-

defined target times are highlighted as warning/fail by the tool and investi-gated for corrective actions. The software analyzes the raw data to capturesuccessful or unsuccessful valve events.

As an example of one of the tools benefits, in the Shah Deniz fields flare stag-ing valves SVTT identified a number of valve openings/closures and recordedtime, prompting an investigation. During shutdown a valve was found to beseized. It had operated about 5,000 times in a year, which led to its breakdown.Based on this process, pressure settings were reviewed to prevent recurrence.

Other issues that the system has identified include: Switch failure; Corrosion; Low valve air pressure; and Sticking valve stem.Another important benefit is the reduction of function tests (preventative

maintenance [PM]) taking advantage of valve movements during operations. In the Caspian AGT region, more than half of the PM is closed out using the SVTT, which saves at least 1,000 man-hours per year (assuming two to threehours of technician time for process isolation, verification, and de-isolation perPM). Considering that some ESDV PM requires train or full facility shutdowns,the closeout of these safety valves PM is estimated to deliver significant value well beyond the man-hour savings.

Around 100 to 120 movements are recorded on average in a month in theregion, and of these between 1% and 3% can be fail messages. For the valvesreported with pass messages, credits are taken and function-test PM is resched-uled accordingly. For the valves in fail or unknown status, a separate list is created, and a detailed analysis is carried out. The valves not complying with the target times are investigated and corrected.

The SVTT has helped BP reduce by half the number of outages needed forroutine periodic function testing of critical safety valves. The recorded informa-tion has provided auditable proof of the valves operational integrity. Continuousvalve performance monitoring also has allowed proactive detection of faultyvalves, enabling early remedial measures and often avoiding the need for majoroverhauls, which require valve removal.

The successes in the Caspian have contributed to making this application a BPstandard across the companys operations worldwide.

EPmag.com | February 2013

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The ability to curtail PM has saved man-hours

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Experts are touting GPUs as a faster, more economicaldata solution for use in E&P operations. IT compa-nies are stepping up to meet the challenge of handlinglarge amounts of data, including in remote 3-D visualiza-tion environments.

Larger dataset sizes and computational needs drivenby techniques to better understand the subsurface have led to a wave of development to meet digital oilfield needs.

E&P companies are finding data solutions by turningto systems developed by companies such as NVIDIA,Cisco, and NetApp. Technical experts from several companies, including Petrobras, participated in Hart Energys three-part Big Data and the Cloud webinar series.

Its not enough just to have good seismic data. You need to have the content to be able to make better drilling decisions and well path locations. So you have data from electromagnetic surveys to help correlate that, said Ty McKercher, a high-performancecomputing solution architect for NVIDIA. And every time you add another data type or a different data type or a different discipline, it introduces delays in the system.

That is where the GPU system steps in to help reducedelays and allow diverse teams to collaborate and viewthat data. Such systems are affordable and allow theleverage of existing knowledge to a familiar tool, McK-ercher said. The technology is being used in complexseismic data processing techniques such as reverse timemigration (RTM), wave equation migration, Kirchhofftime-to-depth migration, and multiples elimination.

He noted that it is important for GPUs and CPUs tocooperate via application codes. This enables tasks to beperformed simultaneously by the two. For example, datafiltering can be done on the CPU while doing computa-tions on the GPU.

Paulo Souza, Geophysical Technology, Petrobras,spoke on the benefits of using hybrid computing forseismic processing. Petrobras started using GPUs in2006 after moving from mainframes. Now GPUs makeup more than 90% of the companys processing power,Souza said.

When using RTM for imaging complex structures onGPUs, Souza said the velocity field is read once per job.Groups of GPUs are used to process a group of shotsone shot at a time per group. And a group of shots isstacked in memory before going to disk about everythree to six hours.

The process involves breaking the data into smallpieces and starting a pipeline to overlap four communi-cation stages.

We have the GPU calculating the bulk of the model.We are moving data from the GPU to the host. Also, we are sending the data to the neighbor, receiving thedata from the neighbor, and copying the data from the GPU.

By using GPUs, Petrobras saw gains of up to 10 timesin performance per price and per watt over traditionalarchitectures.

digitalOIL FIELD

GPU usage grows in digital oil fieldE&P sectors appetite for data drives IT solutions.

Velda Addison, Associate Online Editor

Computationally intensive seismic processing algorithms such as

Paradigms VoxelGeo GPU-based attribute extraction and render-

ing platform can help reduce delays and allow diverse teams to

collaborate and view that data. (Image courtesy of Paradigm)

24-30 DOF-netapp_Layout 1 1/18/13 11:49 AM Page 24

24-30 DOF-netapp_24-30 DOF-netapp 1/17/13 8:43 PM Page 25

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Growing appetite for dataWhen it comes to making room for commonapplications such as email and databases along with highly technical applications such as those involving seismic data and well planning, handling massive amounts of data has presented challenges in the digital oil field.

Many are finding answers and learning ways to virtualize the resources with cloudtechnology as IT companies tout advancessuch as remote 3-D visualization capabilitiesand associated supportive systems as well asother applications.

A lot of the components necessary to createan effective 2-D and 3-D visualization environ-ment have existed separately for quite sometime now, said Stuart Lowery, business devel-opment manager of Data Management andInfrastructure for Paradigm. There are high-

end work stations, large amounts ofmemory, high-end graphics cards,and fast network connections toshared network storage devices. The game-changing event is theevolution of GPUs for both visualiza-tion and computation, he said.

That, coupled with flexible storage and storage virtualization,creates the building blocks to create a remote 3-D visualizationenvironment, he said. The newchallenge is that 3-D graphics capabilities are pervasive and now seen as critical to E&P work-flows. Systems and software are available to support this remote 3-D visualization.

For example, there are widelyavailable graphics capabilities onmany platforms, powerful traditionaldesktops, emerging devices formobile users, and massive computepower in datacenters, he said. Nowwere starting to see hybrid systemswith coupled CPUs and GPUs andeven single chips with both.

Software is capable of combiningdata from different repositories frommultiple sources, displaying them in

NVIDIAs Kepler GPU is the first designed specifically for cloud computing.

(Image courtesy of NVIDIA)

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3-D on remote desktops, and allowing them to beshared by multiple users. That could prove useful whenhandling large amounts of high-resolution data andwell log images as well as raw data coming from thefield. It has even greater importance considering the industrys mobility.

The key is to pool the resources so they can be virtualized and tightly coupled in a secure manner, Lowery said. The datacenter of the future includes a shared data repository as reliable storage, computepower, and graphics that can be shared that are in close proximity to the storage network infrastructurethat connects those. The real key here is they have to be scalable and flexible in providing the low latencyrequired to support remote visualization in an interac-tive way for the user.

Uncovering workflow trendsThe trend for GPUs in the workflow is moving from

the graphics side for interpretation to seismic processing and flow simulation, and efforts are underway to integrate the two with new cloud technology, said Keith Cockeram, energy businessdevelopment manager for NVIDIA. He said that hardware to handle large, expensive data has beensecured; however, data sizes are outgrowing screen resolution.To overcome the challenge, Cockerham said the company has done compression and color space conversions on the hardware itself andincreased algorithms for pixel compression, amongother steps. The company also has developed software to handle the increasing size of datasets, giving power users their own GPUs and memory footprints while others such as those who do notrequire much graphic power share.

As the data volume grows along with the need for collaboration to empower users and handle real-timeinformation, Peter Ferri, energy industry director forNetApp, said the pressure is on IT to get it right. Thereare operational challenges such as security and timeconstraints posed by trying to copy large amounts ofdata to local storage.

There is a proliferation of siloed infrastructure areas that is making it very difficult for companies to efficiently provision services or make changes across multiple software architectures with unintegratedmanagement tools [along with] the inability to fullyleverage assets, which leads to increased costs, he said. However, the companys customers are moving from such rigid silos to a more service-oriented infrastructure.

One solution involved working with Cisco on its FlexPod integrated system, which John Thomas, technical solutions architect, Data Center group for Cisco, explained. The systems features includeextended memory for faster rendering, bigger datasets, more desktops per server, and low latency.

Nearly 40% of all large enterprises have virtualizedthese services, Ferri said.

Using Hess Corp. as an example, Ferri said NetApp has enabled the company to support four times more 3-D seismic interpreters. The company increased efficiency by decreasingbackup time, decreasing data loading performancefrom 20 minutes to one to two minutes, and reducing storage capacity needs by 30%, according to Ferri.

The key enabler is virtualization, he said. Its an evolutionary process.

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OIL AND GAS PRODUCTION ENHANCEMENTTECHNOLOGYBy the use of modified coil tubing technology and high pressurehydraulics the system generates erosional power and pullingpower to penetrate most sedimentary rock formations.

APPLICATIONSThis applies to oil and gas wells, injector or disposal wells, pres-sure maintenance and water flooding projects, chemical injec-tion and frac assistance. It is also designed to apply to shaleand coal development by creating a multitude of angled to hor-izontal drainage channels.

TECHNICAL BENEFITSRadial Jetting creates a borehole by blasting the formation to powder with hi gh pressure fluid (just like a reall y long perforation).

DISTINCT ADVANTAGESThe system relies on erosional power and the pressure generated for penetration are all contained within the system. Once thesepressures are outside the system they have no longer any pressure left to affect the formation balances. The low volumes usedare also minimizing any hydrostatic effects. With the use of very low volume of carefully selected fluids the formation damage isreduced to practically Lero as a result of the formation compatible fluids and the minimum dwell time of these fluids in the well.As compared to frac operations, whereby huge volumes of fluid and pressure are forcing the reservoir to break against its naturalpressure balance, radial drilling system essentially erodes a channel into the formation.

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Defining benchmarks

Seismic technology is arguably one of the mostenabling technologies in the oil and gas industry.But it has its shortcomings.

It is expensive to acquire, particularly on land. Thedata take a long time to process and interpret. And theresults are often ambiguous.

Finally, seismic information is great at illuminatingunderground structures, but it falls short of illuminat-ing underground oil and gas.

NXT CEO and inventor George Liszicasz has devel-oped a technology called the stress field detector (SFD)that he said can be used prior to a seismic survey toidentify potential trapped fluid reservoirs below the sur-face. SFD is a patent-pending airborne technology thatuses airborne gravitational measurements to identifythese reservoirs. The tool is flown in a jet at 3,000 m(10,000 ft) traveling 470 km/hr (285 mph). The sur-veys cost a fraction of what a seismic survey would cost,can be done 90% faster than a seismic survey, andcause no environmental disturbance.

Unlike traditional gravity measurements, which measure gravity magnitude, and gravity gradiometers,which measure the difference in density magnitudefrom one location to another, Liszicasz maintains thatSFD responds to changes in the orientation of Earthsgravity field caused by subsurface stress.

SFD has to be in motion, he said. It couples directlywith the perturbations or the anomalies in the subsur-face. It does not respond to the total magnitude of thefield; it only responds to changes in the gravity field.

The key to the technology is fluids inability to transmitshear. You can cut rocks, and you can tear rocks, andyou can apply forces from different angles, he said. Butyou cant take a pair of scissors and cut your coffee.

The technology was developed when Liszicasz wasworking on a pyroelectric material that could be used inpacemakers to harness the patients body heat to powerthe device. I solved that problem, but in the meantime Imade this discovery, and I forgot all about the otherone, he said.

He removed most of the seats in his van to house thesystem and drove around the US and Canada trying outhis method in different geological environments reefsystems in Michigan, Austin chalk formations in Texas,salt domes in Louisiana, overthrust faults in the foothills,and overpressured reservoirs in Wyoming. Ultimately, hecreated a library of the tools responses to these varyinggeologic settings.

The next step was to swap the van for the jet. NXTdid its first test flight in 1997 and after a lengthy R&Dprocess began offering SFD as a commercial service in 2006.

Its first jobs were in Canada, both in conventionalplays and in the Horn River basin shale play. Since thenNXT has gone international and is currently workingin Mexico and Pakistan, among other places.

Case studies abound. One survey led to the discoveryof a 180-MMbbl field in Colombia, Liszicasz said. Theclient was shooting a 3-D survey over the entire block.For [US] $500,000 we could tell them where to focustheir activities in stage 1 of the exploration cycle.

Technologies like airborne magnetics and gravitycan map basin architecture; 2-D reconnais-sance seismic can identify traps. Wefind trapped fluids. Thats what E&Pcompanies are looking for.

Flying high to find reservoirsTechnology uses gravity perturbations to find potential trapped fluids.

Read more commentary at

EPmag.com

RHONDA DUEYExecutive Editor

[email protected]

explorationTECHNOLOGY


explorationTECHNOLOGY

NXTs SFD equipment is flown at high altitudes and fast speeds

to cause perturbations in the orientation of the Earths gravity

field caused by subsurface stress. (Image courtesy of NXT)

31-32 ExpCOL-FEB_31-32 ExpCOL-FEB 1/17/13 8:43 PM Page 31

31-32 ExpCOL-FEB_31-32 ExpCOL-FEB 1/17/13 8:43 PM Page 32

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ConocoPhillips wants to drill on the blocks in theChukchi Sea that the company leased in 2008. Ifeverything goes according to plan, one or two wellswill be drilled on the Devils Paw prospect about 128km (80 miles) offshore Wainwright, Alaska, duringthe open-water season in summer 2014.

In drilling terms, a jackup is ideal for the ChukchiSea with water depths of 40 m to 42 m (132 ft to 139ft), Randall Shafer, ConocoPhillips, said during apresentation (Offshore Technology Conference PaperNo. 23745) on Use of Jackup Drilling Units in ArcticSeas with Potential Ice Incursions During Open-WaterSeason at the 2012 Arctic Technology Conference inHouston Dec. 4, 2012.

After looking at semisubmersibles, drillships, and jackups, the company chose a jackup based onhigher variable deck load and deck area, a fixed riserto the seabed, surface and seabed BOP controls, andavailability.

The initial wells will be drilled in the Chukchi Seaon blocks awarded to ConocoPhillips during LeaseSale 193.

Based on US National Ice Center data from 1996 to2007, the average open-water season was about 100days from July through October. Open water for the

purpose of evaluating modular offshore drilling unitsis defined as no ice within 45 km (25 nautical miles)of the proposed well location, Shafer noted.

Ice-alert and ice-management systems are keys tosafe operations. All of these systems are designedaround the amount of time it takes to secure the well.It takes us 24 hours to secure a well and jack downthe rig. That varies with the depth of the well, headded. However, we dont expect any ice incursionsinto our area at all. Over the last three years, wehavent had any ice incursions.

An added level of safety is provided by a speciallydesigned prepositioned capping device (PCD), whichconsists of two blind/shear rams and is installed onthe wellhead on the seabed. In the unlikely event ofloss of primary and secondary control from the sur-

face BOP, the PCD can be activated to regaincontrol of the well either from the drilling rigor a nearby vessel. The PCD system is separatefrom the rigs BOP and power source.

ConocoPhillips has been running virtualdrilling exercises for three consecutive yearstimed to the open-water seasons. By July 27,2012, the ice was 45 km away. In the virtualdrilling program, we spudded the well on July30 and completed it by Sept. 2, Shaferexplained. We suspended operations duringthe drilling as a test and still completed thewell. We then moved the rig intothe second position and drilledthat well too. We moved the rigoff location on Oct. 1.

Water depth, availability drive use of jackup in Chukchi SeaConocoPhillips plans to drill one or two exploration wells in 2014 using ajackup rig during the open-water season in the Chukchi Sea.

A new day will dawn for explo-

ration in the Arctic Ocean with

the use of a jackup drilling rig

during the open-water season

in the Chukchi Sea in 2014.

EPmag.com | February 2013

Read more commentary at

EPmag.com

SCOTT WEEDENSenior Editor, Drilling

[email protected]

33-34 DRILLcol-FEB_33-34 DRILLcol-FEB 1/17/13 8:43 PM Page 33

33-34 DRILLcol-FEB_33-34 DRILLcol-FEB 1/17/13 8:44 PM Page 34

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One summer when I was a child I spent my daysriding with my grandfather on his tractor as heworked in his cotton fields. To stop my steady stream ofbut whys?, he would turn me loose to catch the hun-dreds of jackrabbits that called the fields home. Forevery one that I caught, he would pay me US $5. Withempty pockets and a dusty mouth, I would go with himto the coffee shop for lunch. It was there that I firstheard the holy trinity of Texas farmer shop talk: football, cotton futures, and chances of rain.

As summer approaches, the need for rain continuesto be strong across most of the High Plains and south-western US. Exceptional drought has placed extremepressures on state and local water management plans.And in those drought-stricken areas that have rigs work-ing night and day, it is easy to single out the industry asbeing a major consumer of water. People have ques-tions about how much water is being used and why somuch is needed by the industry to frac a we

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