Collaboration on oil and natural gasresearch among DOE’s national laboratorieshas yielded significant energy, economic,and environmental benefits to America.

The Natural Gas and Oil TechnologyPartnership (NGOTP), launched in 1988,brings together the expertise of DOE’snational laboratories in collaborative proj-ects with each other and with the Nation’soil and gas producers, service companies,and academic institutions.

Since its inception, NGOTP and its prede-cessor entities have been the conduit forover $86 million in DOE funding for R&Dprograms in oil and gas technologies. Thepartnership has been the hub of more than120 projects and workshops funded byDOE. NGOTP has contributed to criticaladvances in seismic imaging, basin analysis,

computing, drilling, com-pletion, and productiontechnologies.

Early stagesIn its early stages, a majorfocus of NGOTP was toapply the national defensecapabilities of the Los Alamos and Sandianational laboratories to peaceful means: theexploration and production of oil and natu-ral gas.

David J. Borns, current co-chairman ofNGOTP and geotechnology/engineeringdepartment manager at Sandia NationalLaboratories, recalls the partnership’s gene-sis in the late 1980s as a DOE response toan outreach by independent oil and gas pro-ducers who were whipsawed by severalyears of the worst market bust the industryhad ever seen. The oil and gas industry hadexpressed an interest in benefiting fromDOE laboratory expertise, equipment, andfacilities and in gaining access to defensespin-off technologies that could have near-term applications in improving oil recovery.

“[New Mexico independent producer]George Yates got in touch with [NewMexico Sen.] Pete Domenici and asked howDOE could assist independents in oil recov-ery,” Borns said, in recalling the programcatalyst.

That step led to a memorandum of under-standing (MOU) between the Los Alamosand Sandia labs to kick off an Oil RecoveryTechnology Partnership (ORTP). This initia-tive focused on getting input from industryup front to prioritize research needs andthroughout the program to review projects,with a special emphasis on independents.George Yates’s own company, Harvey E.Yates Co. (Heyco), Roswell, NM, was a par-ticipant in the first project begun under ORTP.

The program was operated throughDOE’s Office of Fossil Energy under theoversight and control of the agency’sNational Energy Technology Laboratory oil

and gas program and the policy and admin-istrative guidance of DOE’s AlbuquerqueOperations Office. The ORTP PartnershipOffice was established under co-chairsRobert J. Hanold at Los Alamos NationalLaboratory (LANL) and David A. Northropat Sandia.

The initial MOU called for an emphasison seismic technology—specifically cross-well seismic—and on helping independentsimprove oil recovery. The first four projects,awarded in FY1989-90, were:

• Stresses and Fractures in a Low-Permeability Oil Reservoir (Heyco and Sandia), which sought to apply Sandia technologies and experience developed for tight gas sands to low-permeability oilreservoirs in the Permian Basin.

• Microseismic Monitoring of the Chaveroo and Tomahawk Oilfields, New Mexico (Murphy Operating Corp. and LANL), which was designed to overcomepremature water breakthrough by using microseismic monitoring to determine thelocation and prevalent orientation of frac-tures.

NGOTP collaboration yields oil and gas R&D benefits

InsideNGOTP/Cover Story . . . . . . . . . . . .1-2

Access Technologies . . . . . . . . . . . . . .3

Optimizing Production . . . . . . . . . .4-5

Alaska Energy . . . . . . . . . . . . . . . . . . .6

Subsurface Imaging . . . . . . . . . . . . . . .7

E&P Snapshots . . . . . . . . . . . . . . . . . . .7

Calendar . . . . . . . . . . . . . . . . . . . . . . . .8

continued on page 2

Vol. 2, No. 1

“There’s still a role for thelabs to play [in oil and gasresearch], and not just tocompete with each other.That’s why I’ve held on—I’m a zealot.”

— NGOTP Co-Chairman David J. Borns

U . S . D e p a r t m e n t o f E n e r g y • O f f i c e o f F o s s i l E n e r g y • N a t i o n a l E n e r g y Te c h n o l o g y L a b o r a t o r y

This is the first offour articlesappearing in E&PFocus this year onthe Natural Gasand Oil

Technology Partnership.

• Development of a Multi-Station BoreholeSeismic Receiver (OYO Geospace and Sandia), which called for designing, developing, and field-testing a multi-sta-tion, three-component borehole seismic receiver for improved crosswell seismic surveying.

• Imaging the Faults in the McKittrick Oilfield (Texaco USA, Chevron Oil FieldResearch Co., and LANL), which focusedon evaluating crosswell surveying tech-nology for delineating saturation bound-aries and complex faults controlling pro-duction in a large producing sand in cen-tral California.

NGOTP evolvesThe ORTP later spread its focus to concen-trate on three general areas: Drilling andProduction, Oil Recovery, and CrosswellSeismic.

Drilling and Production evolved intoDrilling and Completion Technology. Thenthe Drilling, Completion, and Stimulation(DCS) area was added to the partnership in1992. DCS currently focuses on developingand demonstrating innovative drilling, per-forating, and fracturing processes; subsur-face instrumentation; and advanced soft-ware.

Crosswell Seismic was renamed BoreholeSeismic Technology, which eventually begatDiagnostic and Imaging Technology.Research in this area strives to improveexploration and reservoir characterizationthrough advances in borehole geophysicsand seismic processing and imaging.

In 1994, Oil Recovery gave way to Oiland Gas Recovery, as the partnership’sscope was expanded to include natural gasexploration and production research. Thateffort also prompted a switch to the partner-ship’s current name. In the same year,Lawrence Berkeley (LBNL) and LawrenceLivermore national laboratories joinedNGOTP.

The following year saw saw the additionof Argonne, Brookhaven, Idaho (INL),Pacific Northwest, and Oak Ridge nationallaboratories to the partnership.

Computational Technology became thefourth technology area of the partnership in1995, although that proved short-lived, asthe computational technologies projectslater were folded into the three main tech-nology areas.

NGOTP subsequently added Upstreamand Downstream Environmental technologyareas in 1997-98 and organized a NaturalGas Technology area in 2002 with twosubtopic areas: Gas Storage and DCS(which focused on gas drilling, completion,and production success in harsh-reservoirenvironments).

Today, NGOTP is the home for more than50 active projects. Any natural gas or oilproducer, refiner, or service company is eli-gible to participate in the partnership, pro-vided the participant teams with a nationallab. Universities and other research institu-tions also may join project teams. The pro-gram is entirely industry-driven, in that itestablishes active industry interfacesthrough review panels and forums thatdefine industry needs, provide annual proj-ect reviews, and determine the priority ofnew proposals and ongoing projects.

Partnership perspectiveBorns, who succeeded Hanold and Northropin 1998, said NGOTP always has beenviewed as an expanding, multi-year pro-gram.

“The rationale was to devevelop a fast,flexible, and simple program that wasindustry-focused,” he said.

There also were areas where the variouslabs’ strengths would dovetail to the benefit

of the research. Bornscited a $1 million-per-year project in which anindependent requestedthat several of the labswork together on a proj-ect involving single-

borehole seismic technology: LANL andSandia had experience in seismic technolo-gy, LBNL specialized in microinstrumenta-tion, and INL had developed a high-broad-band capability, he said.

Apart from the synergies and comple-mentary strengths of the national labs work-ing together on critical technology needsthat industry wasn’t otherwise undertaking,the partnership helped DOE simplify its oiland gas research programs.

“Instead of all of the national labs liningup to DOE and pleading for funding,[NGOTP] was a way to prioritize their [oiland gas] research needs to DOE,” Bornssaid.

“It also got people to work together”

because of funding limits, he noted. “A sin-gle lab project could be funded at only$350,000. If you wanted more for your proj-ect, you had to work with another lab.”

About 5% of partnership funding went tothe national labs for overhead expenses—including running the industry commit-tees—related to NGOTP projects, he noted.

NGOTP successesOn balance, however, Borns points proudlyto the partnership’s research successes over-shadowing the few bumps in the road. Hecited important technology advances madein the areas of 3-D seismic, polycrystallinediamond compact bits, characterizingdiatomaceous oilfields in California, drillcuttings injection, tiltmeter technology formonitoring hydraulic fractures, early micro-hole efforts, and optimizing algorithms formassively parallel computing in oil and gasapplications.

Success has marked the program from thebeginning. Borns noted that Heyco was ableto double production from the Shoestringsands of the Delaware Basin in West Texasas a result of NGOTP research.

He also pointed to BP USA’s kudos forNGOTP’s Gulf of Mexico wellbore stabilityresearch, to which the company attributedsavings of more than $30 million in itsdeepwater Gulf of Mexico oil and gasdevelopment program.

Borns sees continuing value in collabora-tion on oil and gas research: “Our focusshouldn’t be as competitors on technology.There is still a lot of [collaborative] researchthat can be done that’s of value to the oiland gas industry,”

He cited deepwater oil and gas, deep gas,and oil shale as prospective areas for newand continuing collaborative researchamong the national labs.

The longtime advocate of NGOTPacknowledges his continuing role with thepartnership has evolved into a “part-time,gratis” role versus his earlier years with it,when “for a while, it took over my career.

“There’s still a role for the labs to play[in oil and gas research], and not just tocompete with each other,” Borns added.“That’s why I’ve held on—I’m a zealot.”

2 1Q 2006 E&P Focus

continued from page 1

A U.S. Department of Energy-funded tech-nology has been commercialized that estab-lishes a “downhole Internet” for drilling oiland natural gas wells.

The technology turns ordinary drill pipeinto a two-way highway for transmittingdrilling and formation data atblazing speed from bottomhole tothe surface and vice-versa.Potential benefits includedecreased costs, improved safety,and reduced environmentalimpacts of drilling.

Grant Prideco, a leading drillpipe manufacturer, announced thecommercial launch of itsIntelliServ® Network and relatedIntellipipe® technology at a pressconference in Houston, TX, inFebruary. Contract talks alreadyare underway with several majoroil and gas operators. Theannouncement caps 5 years ofresearch under a project spon-sored by DOE and managed byDOE’s National EnergyTechnology Laboratory.

For decades, the “Holy Grail”of drilling has been the ability to“look ahead” of the drillbit: gath-ering a wide range of downholedata—pressure, temperature, wellposition, formation characteristics, etc.—inas close to “real” time as possible.

Until now, no method of hard-wiring pipewith electrical wire connections to transmitthese data has proven reliable. The cou-plings that connect the jointed drill pipewere a barrier; manipulating the drill pipedownhole usually broke the electrical con-nection.

DOE-funded technology provided a par-tial answer 30 years ago, with the inventionof mud-pulse telemetry. But the pace of thisdata transmission method is glacial at 3-10bits per second, which typically yields poor-quality data and hobbles a driller’s ability tomake crucial decisions quickly.

Intellipipe® accelerates that transmissionrate exponentially—to 57,000 bits per sec-ond. An IntelliServ® network upgradewould boost that to a staggering 1 millionbits per second. Not only can a drillerreceive crucial downhole information quick-ly with Intellipipe®, he can immediately“tell” a drilling tool what to do thousands offeet below the surface.

Having this real-time capability reduceseconomic and safety risk in drilling wellswhile it minimizes the number of wellsneeded to produce oil or gas from a reser-voir. It also cuts down on the number ofunplanned trips downhole to resolve drilling

problems and eliminates the associated non-productive time and well costs.

Here’s how it works: Intellipipe® fea-tures high-speed, high-strength data cableembedded in the inside wall of the drillpipe. These cables carry data to small induc-tion coils that are installed in protectivegrooves machined into the couplers. Whentwo sections of Intellipipe® are joined, theinduction coils are placed close together,and a low-energy data signal can transmitpassively between them without a dedicatedpower source—from one pipe section toanother, along a string of tens of thousandsof feet of drill pipe. There is no physicalconnection to break.

The system already has proven remark-ably reliable in extensive U.S. and Canadianfield trials. Since 2004, Intelliserv® drillstrings of 14,000 feet in Oklahoma and10,000 feet in Alberta have drilled 18 wells,accumulating more than 6,000 hours of

operation while drilling 180,000 feet. In addition, measurement-while-drilling

and logging-while-drilling tools weredeployed in these field trials, demonstratingthe Intelliserv® network’s ability to transmithigh-volume data continuously from a wide

variety of tools. Such a high-speed network also serves as anenabling technology for evenmore sophisticated diagnostictools not yet on the market.

At the same time, beingable to deploy a real-time down-hole data transmission networklets drillers process more of thewell and formation data at thesurface rather than downhole;this allows them to use muchlower-cost, more-rugged down-hole sensors. The upshot: a dra-matic cost reduction for oil andgas companies tackling theincreasingly difficult and harshdrilling environments of today.

Novatek Engineering,Provo, UT, developed theIntellipipe® technology under aDOE-funded project. GrantPrideco, Houston, TX, subse-quently formed a joint venturewith Novatek to market the rev-olutionary drill pipe; Grant

Prideco now owns the Intelliserv® Network100%.

The first commercial deployment of thetechnology is expected to occur in the NorthSea, with an application that could breakextended-reach drilling records. That wouldput it at about 5 miles—beyond the currentcapability of mud-pulse technology to gath-er data and control wells.

In its final report to DOE after wrappingup its research project, Novatek commendedthe agency’s participation as being essentialto the development of Intellipipe® technol-ogy.

“Particularly in the early stages of thedevelopment effort, the risk was very high,and industry motivation to invest in such agiant leap forward was low,” the report stat-ed. “DOE vision and willingness to beinvolved in this technology has providedNovatek with the needed resources to getpast the early stages and to develop the nec-essary technology.”

31Q 2006 E&P Focus

Access Technologies

Revolutionary ‘smart’ drill pipe creates ‘downhole Internet’

Intelliserv® system.

4 1Q 2006 E&P Focus

Optimizing Production

A U.S. Department of Energy-fundedresearch and technology development proj-ect has breathed new life into one ofAmerica’s biggest mature producing oil-fields.

The project is expected to add ultimately13 million barrels of incremental oil produc-tion in a small portion of Wilmington oil-field, a 73-year-old giant in the heart ofLong Beach, CA. If the new technology andinnovative techniques developed under theproject are applied field-wide, it could resultin boosting Wilmington’s ultimate oil recov-ery by 525 million barrels of oil. Achievingthat jump in a single oilfield equates to a2.5% increase in total U.S. proved oilreserves. An aggressive effort to transferthis technology could boost reserves in sim-ilar fields along the California coast by 1.4billion barrels of oil.

Giant’s historyWilmington, discovered in 1932 and thethird largest oilfield in the contiguousUnited States, has ultimate recoverablereserves estimated at 3 billion barrels of oiland cumulative production to date of 2.5billion barrels. Expansion field-wide oftechnology and techniques developed underthe DOE project could more than doubleWilmington’s remaining proved reserves.

The project, managed by DOE’s NationalEnergy Technology Laboratory, originallyhad envisioned an increase in production inthat targeted portion of Wilmington fieldfrom 8,000 barrels per day of “heavy,” orhighly viscous, oil in 2005 to 9,600 barrelsper day in 2010. A drilling program basedon lessons learned from the DOE researchalready has hiked oil production in the tar-get area from 6,100 barrels per day in 2002to an average 8,793 barrels per day inNovember 2005—a level researchers didn’texpect to achieve before late 2007.Expectations now are that the project willreach almost 10,000 barrels per day by theend of this year.

A small, independent producer, LongBeach-based Tidelands Oil Production Co.,operates the western portion of the field as asubcontractor to the field owner, the City ofLong Beach. Wilmington has been one ofSouthern California’s mainstay producersfor decades, currently producing 46,000 bar-rels of oil per day from 1,550 wells. Thefield lies in a 13-mile-long geologic struc-ture that extends from the onshore commu-

nity of San Pedro along Los Angeles Harboracross Long Beach to offshore Seal Beachin the Long Beach Harbor area. Of specialconcern are ecological sensitivities in aheavily populated coastal area of a statewidely regarded by industry as having theworld’s most stringent environmental regu-latory regime.

Since 1932, more than 3,400 land-basedwells have been drilled in the western por-tion of Wilmington oilfield. By the 1950s,that portion of the field had been completelydeveloped under primary recovery, andwaterflooding was started in order toincrease recovery and control subsidence.These efforts were followed by a long pro-gram of steamflooding.

Steamflooding, typically an expensiveprocess, had been economic in Wilmingtonfield even when oil prices were low,because the operators had access to a low-cost source of steam from a nearby powerplant. However, inexpensive steam isn’texpected to be available to Wilmingtonoperations in years to come, as the powerplant has shut down. Future expansion ofthermal recovery to other parts ofWilmington field depends on improving theefficiency and economics of heavy oil

recovery apart from the steam source.

DOE project detailsTidelands’ project called for using advancedreservoir characterization and thermal pro-duction technologies together with horizon-tal drilling to improve the efficiency of adeep, heavy oil steamflood in Wilmingtonfield. The main producing horizon atWilmington is a reservoir characterized asslope-and-basin clastic (SBC).

The DOE-funded project addressed sever-al producibility problems in two large por-tions of Tidelands’ operating area that arecommon to SBC reservoirs. Difficultieswith oil recovery arose frequently becausethe targeted Wilmington formations are rela-tively deep, high-pressured, and heteroge-neous compared with those found in thermalEOR projects elsewhere in the state.

Among many other innovations,Tidelands developed:• An advanced computer model to simulate

the Wilmington reservoir, which it used to optimize steam, hot water, and water injection with oil production efforts with-out causing surface subsidence—a peren-nial problem in the field.

• A series of operational changes based on

DOE project breathes new life into aging California giant

Location of Wilmington oilfield.

51Q 2006 E&P Focus

the new reservoir model to improve heat efficiency, reduce costs, and expand steamflood operations.

• New horizontal steamflood pilots, with the aid of new 3-dimensional computer models.

• A novel alkaline-steam well completion technique that controls excessive produc-tion of sand in the wellbore, cutting capi-tal costs by 25%.

• New ways to reduce the formation of scale minerals in the producing well-bores, further trimming well costs.

• A new, commercial technology to scrub out deadly hydrogen sulfide gases createdin the steamflood at a 50% cost reduc-tion.

• A new steam generator that can burn a variety of low-quality waste gases createdby the thermal EOR operations.

Project benefitsAs a result of these innovations, Tidelandsin 2003-2005 enjoyed the most successfulround of drilling in the Wilmington onshorefield area in 20 years. The company attrib-utes these successes to technologies trans-ferred from earlier DOE reservoir-classresearch. Several of these technologies havesince been commercialized by service com-panies, been adopted or further researchedby other oil companies, or used byTidelands in other operating areas. Thecompany said it expects some of its innova-tions to spread to other operators in the LosAngeles Basin, one of the Nation’s mostprolific—yet high-cost and environmentally

sensitive—producing areas.The project, entering its final

phase, started up in 1995 and isslated to end early in 2007. DOEfunding is expected to accountfor 40% of the project’s estimat-ed total cost of more than $20million.

NETL project manager JimBarnes, based in Tulsa, OK,noted that two significant com-panies have started up as a resultof the project: DynamicGraphics, Inc. (DGI), Alameda,CA, and GeomechanicsInternational, Inc. (GMI),Houston, TX.

“DGI started expansion in themid-1990s after they realized theeffectiveness of 3-D modeling indescribing a complex reservoirand oilfield such as Wilmington;since then, they have become a3-D modeling provider of choiceto small and mid-size Californiaindependent operators who haveseen the value of this technologyfor complex reservoirs,” Barnessaid. “Tidelands teamed withStanford and the University ofSouthern California during manyof their investigative efforts; GMI was acompany during this time that came out ofStanford researchers, who developed dipoleacoustic/sonic [well] logs calibrated toaccurately measure porosity and oil satura-tion through acoustic wave technology.”

Tidelands’ Wilmington project is one of anumber that DOE supported in its ReservoirClass Oil Field Recovery program. Begunin 1991, the program targeted geologicclasses of U.S. oilfields that were on theverge of being prematurely abandoned.With federal matching funds allowing high-er-risk technologies to be tried, many opera-tors have been able to keep oil flowing fromthese fields long after conventional wisdomlabeled them “depleted.”

There are many other large, mature SBCreservoirs in the U.S., notably elsewhere inCalifornia and in the Gulf of Mexico. Withthe new technologies and innovative tech-niques emerging from Tidelands’ ambitiousproject at Wilmington, other venerable U.S.oilfield giants can win a new lease on life aswell.

A pumpjack working in giantWilmington oilfield in the LongBeach, CA, area. The large, wrappedpipeline in the foreground is asteamline.

Wilmington project area dailyproduction history and forecast.

A DOE-funded research project has takenanother important step toward determiningthe technical and economic viability ofAlaska’s methane hydrate resource.

Success in this project could help lay thegroundwork for unlocking a resource thatcould be an important contributor to futureenergy demand.

BP Exploration Alaska Inc. has filed withstate authorities a plan of operations fordrilling a stratigraphic test well to probe alarge hydrate resource on the Alaskan NorthSlope (ANS). BP is studying possible gravelpad sites for the summer, with an eye tospudding the well during the 2006-2007winter drilling season.

The stratigraphic well—and the data itacquires—is the critical next step in a 5-year, nearly $25 million research project togauge the potential for ANS methanehydrate to become part of the Nation’s ener-gy supply portfolio.

The ultimate pay-off could be huge.The U.S. GeologicalSurvey (USGS) haspostulated that 44-100 TCF of methanehydrate in-placeunderlies the NorthSlope oilfield infra-structure in theEileen and Tarntrends (see map).The overall NorthSlope hydrateresource is pegged at590 TCF.

The research project delineated more thana dozen drillable hydrate prospects contain-ing more than 600 billion cubic feet of gaswithin the North Slope’s Milne Point Unit(MPU) alone. Extending these findingsthroughout the greater Prudhoe Bay areayields an estimated 33 TCF of original-gas-in-place in the Eileen Trend. Reserve mod-eling indicates commercially viable produc-tion is possible, with as much as 12 TCF inthe greater Prudhoe Bay area technicallyrecoverable with tailored applications ofmostly existing extraction technologies.

That number may not seem large in lightof a remaining technically recoverable U.S.natural gas resource estimated at 1,400 TCF.However, with a total U.S. in-place hydrateresource of 200,000 TCF, even a 2.5%

recovery rate puts the postulated recover-able domestic hydrate resource base at5,000 TCF. That’s more than double thecombined cumulative production andremaining technically recoverable resourceof domestic natural gas. America’s remain-ing proved gas reserves total 190 TCF.

The knowledge obtained in the BP strattest could be one of the critical first steps tounlock that massive potential contribution toAmerica’s gas supply.

BackgroundIn 2000, BP proposed donating a state-of-the-art 3-D seismic survey over its MPUproduction area. This was to provide a start-ing point for fully evaluating the feasibilityof commercial production from arctichydrates.

The project’s first phases were designedto integrate detailed geophysical interpreta-

tion and modeling, regional geologic charac-terization of the prospective hydrate-bearingunits, and advanced reservoir and economicmodeling to choose a site for drilling, cor-ing, and production testing.

The near-term goal is to test the science—the tools and techniques—of delineatinghydrate prospects, and then to model theirpotential productivity and commerciality. Ifthe project proceeds through all four pro-posed phases, the end result will be theworld’s first extended production test of agas hydrate reservoir. The idea is to gleaninsights into the relative merits of various

production and stimulation approaches thathave been considered for this vast but elu-sive resource.

DOE participated in two other importantNorth American Arctic wells that have con-tributed to industry’s body of knowledge onhydrates. The Mallik hydrate drilling pro-gram, undertaken in 2002 on the MackenzieDelta in Canada’s Northwest Territories,conducted several brief experiments thatconfirmed that producing gas from hydratesis technically feasible. The Hot Ice No. 1well, drilled in 2003-04 in the KuparukRiver oilfield area, failed to encounterhydrates but yielded a wealth of informationfor researchers.

Project detailsHaving completed the first two phases ofthe project, BP launched Phase 3 in October2005.

This latest phaseincludes thedrilling of one ormore wells throughthe hydrate stabili-ty zone, with com-prehensive petro-physical analysesof targeted zones.The plan of opera-tions BP submittedto Alaska’sDepartment ofNaturalResources/Divisionof Oil and Gas at

the end of January 2006 calls for drilling theMt. Elbert-01 gas hydrates stratigraphicwell a half-mile east of the MPU E pad,about 28 miles west of Deadhorse, AK.

This drilling will test various geophysicalexploration techniques in order to select tar-get zones and field parameters for the fourthand final phase: production testing. Movingon to Phase 4 depends on Phase 3 resultsand the approval of both DOE and BP.

DOE is providing about $19 million infunds for the cooperative agreement withBP and managing the project through itsNational Energy Technology Laboratory.

Other project partners include ASRCEnergy Services, University of Alaska-Fairbanks, University of Arizona, USGS,Interpretation Services, Ryder-Scott Co.,and APA Petroleum Engineering.

6 1Q 2006 E&P Focus

Crucial well slated to test Alaska methane hydrate resource

Alaska Energy

Alaska North Slope methane hydrateestimated in-place resource totals 590trillion cubic feet.Source: U.S. Geological Survey

71Q 2006 E&P Focus

A DOE research project is advancing thescience of crosswell seismic—a novel tech-nique for imaging oil and gas reservoirs inhigh resolution by using existing boreholes.

By lowering the seismic signal generatorand receiver into the boreholes, crosswellseismic eliminates much of the subsurfaceinterference that diffuses the signals. Thistechnique can delineate images as small as 5feet across, compared with about 50 feet forconventional surface seismic.

Project performer Michigan TechnologicalUniversity, Houghton, MI, is now process-ing and analyzing data it recently acquiredto obtain a high-resolution crosswell imageof a producing carbonate reef in northernMichigan.

If proven successful, the project resultswill help operators of carbonate reefs—acommon reservoir type in the UnitedStates—to use their existing boreholes toimage the reservoir. This has the potential toadd billions of barrels to U.S. oil and gasreserves without the added environmentalimpact of dedicating new wellbores to seis-mic sensor emplacement.

MichiganTech, togetherwith partner Z-Seis Inc.,Houston, TX,bracketed thetarget reservoirwith a seismicsource in one well and a string of receiversin another. Like many other carbonatereefs, this reservoir has a low recovery rate.High-resolution imaging of the reef andthousands of others like it will enable opera-tors to recover a much greater percentage ofthe original-oil-in-place, while minimizing

the expense and environmentalimpact of added wells.

Researchers described theinitial data set quality as“extraordinarily good,” delin-eating the internal structure ofthe reef. The data are beinginterpreted in terms of ampli-tude-versus-angle (AVA) inorder to find relationships withlithologic facies and fluid con-tent. The high frequency con-tent of the data requires added

processing in order to “flatten” eventsprior to stacking. Some events are lostin stacking due to the resolution of thedata exceeding the resolution of thevelocity model, but these will berecovered as part of the AVA study.

Michigan Tech has begun talks to acquirea second data set in another producing fieldin Michigan in order to refine the technique.

DOE is funding about 80% of the$900,000, 3-year project under its AdvancedDiagnostics and Imaging research area.

Subsurface Imaging

Progress reported in Michigan crosswell seismic project

The Department of Energy has launched asolicitation to fund new research in tech-nologies that entail injecting carbon diox-ide (CO2) to boost recovery of theNation’s oil and natural gas resourceswhile also serving to safely store CO2,rather than emit the greenhouse gas intothe atmosphere.The DOE solicitation sup-ports producers of oil and gas in carryingout enhanced oil and gas recovery proj-ects to inject CO2 in order to improve oilor gas recoverywhile increasingsequestration ofCO2. The proj-ects will be man-aged throughDOE’s NationalEnergyTechnologyLaboratory(NETL). Details ofthe solicitation and of DOE’s current

portfolio of CO2 projects are pro-vided in a new brochure NETLhas published. It can be downloadedfree at NETL’s online reference shelf,under Technologies/Oil and Natural GasSupply, at www.netl.doe.gov.

About 110 representatives of large andsmall oil and gas producers, supportingindustries, and academia attended theFebruary 22 Pre-Proposal Workshopfor the Funding Opportunity onEnhanced Oil and Natural GasProduction through CarbonDioxide Injection. Facilitated by thePetroleum Technology Transfer Council,the interactive meeting provided potentialproposers with information contained in10 basin-oriented, CO2 EOR assessmentsdeveloped in cooperation with NETL andon state-of-the-art technologies forresource characterization, imaging, model-ing, and mobility control, as well as supplyand recycle operations and monitoring.

While most participants came from theHouston area where the workshop washeld, almost half came from Canada and14 other States as far as Alaska, NorthDakota, and Montana. Mandated underthe Energy Policy Act Section 354, thefunding opportunity seeks project propos-als by May 5 for the enhanced recovery ofoil or natural gas in conjunction with thesequestration of CO2.

On January 30-31, NETL’s ArcticEnergy Office (AEO), in conjunctionwith University of Alaska-Fairbank’s (UAF)Arctic Energy Technology Lab, had its firstannual review presentation in Anchorage,AK. Twenty-three presentations on ongo-ing UAF and AEO projects were given,including reports on CO2 sequestration,Cook Inlet gas demand, Beluga coal gasifi-cation,Arctic lakes, rural coalbed naturalgas, low-rank coal grinding, Bristol Bay gasand oil potential, and the InternationalPolar Year.

E&P SNAPSHOTS

U . S . D e p a r t m e n t o f E n e r g y • O f f i c e o f F o s s i l E n e r g yN a t i o n a l E n e r g y Te c h n o l o g y L a b o r a t o r y

The processed crosswell seismicimage is shown in color, withcolors representing seismicvelocities, and the overlayshowing the seismic reflectiontraces as wiggles with positivevalues blackened.

Calendar of Events/2006

Apr. 4-5SPE/IcoTA, Coiled Tubing & Well Intervention Conference &Exhibition, The Woodlands,TX.Contact: www.spe.org.

Apr. 9-12AAPG, Annual Convention, Houston,TX.Contact: www.aapg.org.

Apr. 22-26SPE, Improved Oil Recovery Symposium,Tulsa, OK.Contact: www.ior2006.org.

May 1-3IOGCC, Midyear Meeting, Point Clear,AL.Contact: www.iogcc.state.ok.us.

May 1-4SPE, Offshore Technology Conference, Houston,TX.Contact: www.otcnet.org.

May 18IADC, Drilling Onshore America Conference & Exhibition,Houston,TX. Contact: www.iadc.org.

June 12-14IPAA, Midyear Meeting, Naples, FL.Contact: www.ipaa.org/meetings.

June 12-16API, Exploration & Production Standards Conferenceon Oilfield Equipment & Materials, Atlanta, GA.Contact: www.api.org/events.

Sept. 20-22IADC, Annual Meeting, San Antonio,TX.Contact: www.iadc.org.

Sept. 25-27SPE, Annual Technical Conference & Exhibition, San Antonio,TX. Contact: www.spe.org.

Oct. 1-6SEG, International Exposition & Annual Meeting, NewOrleans, LA. Contact: www.seg.org.

Oct. 15-17IOGCC, Annual Meeting, Austin,TX.Contact: www.iogcc.state.ok.us.

Oct. 23-25IPAA, Annual Meeting, Grapevine,TX.Contact: www.ipaa.org/meetings.

Nov. 28-29IADC, Drilling Gulf of Mexico Conference & Exhibition,Houston,TX. Contact: www.iadc.org.

E&P Focus is a publication of the U.S.Department of Energy’s National EnergyTechnology Laboratory. It features high-lights of DOE’s E&P research program.

Roy LongE&P Technology Manager918-699-2017roy.long@netl.doe.gov

Visit the NETL website at:www.netl.doe.gov

Customer Service:1-800-553-7681

National EnergyTechnology Laboratory

626 Cochrans Mill RoadP.O. Box 10940Pittsburgh, PA 15236-0940

3610 Collins Ferry RoadP.O. Box 880Morgantown, WV 26507-0880

One West Third Street, Suite 1400Tulsa, OK 74103-3519

2175 University Avenue South, Suite 201Fairbanks, AK 99709-4910

1450 Queen Avenue SWAlbany, OR 97321-2198