Exploration Process Data

26 Oilfield Review

Reducing Exploration Risk

Jose Camara AlfaroPemexTampico, Mexico

Chris Corcoran Shell Exploration and ProductionHouston, Texas, USA

Kevin DaviesChevronLondon, England

Francisco Gonzalez PinedaPemexReynosa, Mexico

Gary HampsonChevronSan Ramon, California, USA

David HillGatwick, England

Mike HowardBHP BillitonHouston, Texas

Jerry KapoorNick MoldoveanuHouston, Texas

Ed KraghCambridge, England

For help in preparation of this article, thanks to Robert Balaguerand Mario Kieling, Rio de Janeiro; Andy Coutts, PatriciaMarçolla, Raúl Teran and David Wilson, Houston; Alberto De Anda, Mexico City; Richard Harding, BHP Billiton,Houston; and Richard Salter, Kuala Lumpur.Q-Fin and Q-Marine are marks of Schlumberger.

With energy demand rising and production from mature fields on the decline, oil and

gas companies are expanding their exploration activities into increasingly challenging

areas—deep water, beneath salt and basalt, and in carbonate reservoirs. These

environments often yield murky seismic images, but innovative marine-seismic

technology can now provide high-quality results to reduce risk in these settings.

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Exploring for oil and gas is a risky business. Byincreasing the likelihood of drilling success,3D seismic surveys have probably done morethan any other modern technology to mitigatethis reality. In the 1970s and 1980s, before theuse of 3D surveys, the exploration drillingsuccess rate in the USA was approximately 25%.Once E&P companies started using 3D surveyswidely, the success rate for exploration wellsincreased to almost 50% by 2005, and fordevelopment wells the rate reached 88%.1 Whileadvances in other technologies such as drilling,LWD, visualization and real-time data deliveryhave also contributed to these success rates,explorationists credit 3D seismic methods withhaving the greatest impact.

While three-dimensional seismic applicationshave led to an improvement in overall explora -tion drilling success, in some situations, thesuccess rate is still low. For example, in 2006, of 119 Gulf of Mexico exploration wells drilled in deep water—water deeper than 1,000 ft[300 m]—only 11 hit pay.2 This 10% success rateis typical of deepwater exploratory drilling in theGulf of Mexico in the last decade.3 Withdeepwater wells costing up to US$ 100 million, itis not surprising that oil and gas companies are looking for ways to reduce the frequency ofdry holes.

Many companies consider the current level ofrisk unacceptable. From 1996 to 2000, oil and gascompanies bought 3,000 leases in the Gulf ofMexico. Of these, only 8% have been drilled.4

Because high rig demand will keep drilling costsfrom declining in the near future, operatorsawait additional advancements in technology toincrease their likelihood of success.

The 3D seismic surveys that did so much toimprove drilling success rates on land and inshallow water are not always adequate forexploration in deep water and other problematicareas, such as beneath hard seafloors, salt, basaltand carbonate layers. Complex geology andhighly refractive layers cause ray bending thatleaves portions of the subsurface untouched byseismic waves. Also, noise from near-surfacereflectors can mask the weak signals returningfrom deep formations.

Deepwater subsalt prospects have beenparticularly difficult to image properly. Whileseveral fields have been discovered in the Gulf ofMexico in the past decade using 3D seismictechnology—Atlantis, Mad Dog, Neptune, Puma,Shenzi and Tahiti are a few that together holdmany billions of barrels of oil—only a small partof the total resource is under development

(above). In some cases, the quality of seismicdata may have served exploration purposes, butit may not be good enough to create accuratemodels for reservoir development.

Recent improvements in seismic dataacquisition and analysis may be the answer toachieving seismic images that are good enough toreduce the risk of drilling wells in these difficultareas. This article explains how new practices insurvey acquisition and data analysis areimproving the information gained from 3Dmarine seismic surveys. We describe innovationsin seismic illumination made possible by probingseismic targets from several angles, and discussnew vertically aligned configurations of sourcesand receivers that are increasing signal quality in

hard-to-image areas. Advances in imaging havealso helped reposition development wells in anoffshore carbonate reservoir and in a deepwaterheavy-oil field. Examples from the Gulf ofMexico, West of Shetlands, and offshore Mexicoshow how improvements in seismic technologyare reducing drilling risk.

Typical Marine Seismic SurveysA typical 3D marine seismic survey is acquired bya ship towing airgun seismic sources andstreamers, or cables instrumented withreceivers. The ship “sails” in a predetermineddirection above a subsurface target, the airgunsemit seismic energy, and the receivers recordsignals that propagate from the sources down to

1. Crude Oil and Natural Gas Exploratory Wells, SelectedYears 1949–2005, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec4_13.pdf (accessed February 25, 2007).Crude Oil and Natural Gas Exploratory and DevelopmentWells, Selected Years 1949–2005, http://www.eia.doe.gov/emeu/aer/pdf/pages/sec4_11.pdf (accessed February 25, 2007).Farris A: “Guest Editorial: Emerging Technology and ItsImpact on the Industry,” JPT Online (October 2006),http://www.spe.org/spe/jpt/jsp/jptmonthlysection/0,2440,1104_11038_5742058_5742529,00.html (accessedFebruary 26, 2007).

2. Paganie D: “Deepwater GoM Key with 50 Bboe of Undis-covered Reserves,” Offshore 67, no. 1 (January 2007): 46,http://www.offshore-mag.com/display_article/283060/9/

ARCHI/none/none/Deepwater-GoM-key-with-50-Bboe-of-undiscovered-reserves/ (accessed March 29, 2007).

3. “Deepwater Gulf of Mexico 2006: Interim Report of 2005Highlights,” U.S. Department of the Interior, MineralsManagement Service, Gulf of Mexico OCS Region,http://www.gomr.mms.gov/homepg/whatsnew/techann/2006/2006-022.pdf (accessed February 27, 2007).“Deepwater Gulf of Mexico 2005: Interim Report of 2004Highlights,” U.S. Department of the Interior, MineralsManagement Service, Gulf of Mexico OCS Region,http://www.gomr.mms.gov/homepg/whatsnew/techann/2005/2005-023.html (accessed February 27, 2007).

4. Paganie, reference 2.

> Recent subsalt discoveries in the Gulf of Mexico, containing billions ofbarrels of oil.

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subsurface reflectors and back. The process isrepeated at defined spatial increments until therequisite number of seismic traces has beenrecorded (below).

The current standards in seismic acquisitionhave evolved from towing a single streamer in the1970s and waiting 10 minutes between dynamiteshotpoints to the highly efficient operations ofmodern surveys.5 Now, vessels tow eight to tenstreamers at a time, separated by 50 to 150 m[160 to 490 ft]. Each streamer may be from 6 to8 km [4 to 5 miles] long. The source consists ofan array of 12 to 18 airguns, and may be firedevery 10 to 20 seconds. These general valuesapply for many 3D surveys, but the exactacquisition parameters will vary depending on

the survey plan, which balances geophysicalobjectives and economic constraints.6

The survey plan also specifies the depth atwhich the sources and streamers should be towedto minimize noise and maximize signal. Towingstreamers at a shallow depth—less than 8 m[26 ft]—better preserves the high-frequencycontent of the signal, but affects the low-frequency content and also increases the noisefrom waves and weather. Deeper towing betterretains the low-frequency content, and soincreases depth of penetration, but at the expenseof high-frequency content. A typical towing depthfor streamers is less than 10 m [33 ft].

Similar trade-offs must be considered whendetermining the tow depth of the source. Airgunsource arrays typically are towed at a depth of 5 to 10 m [16 to 33 ft], depending on the requiredfrequency bandwidth.

Another aspect of typical marine seismicacquisition is the collection of signals from agroup of receivers into a single recorded trace.Standard streamers carry hundreds of hydro -phone receivers spaced 0.5 to 1 m [1.6 to 3.3 ft]apart, with groups of 12 to 24 hydrophones feedingto a single recording channel. In principle,summing the traces in a group before recordingenhances signal-to-noise ratio. But this processcan irreparably damage signal fidelity and reducethe effectiveness of noise-reduction processing.

28 Oilfield Review

> Acquisition of a typical 3D marine seismic survey. A vessel towing sources and receiver cables sails above the target in a direction specified by thesurvey plan (bottom). The length of each loop includes additional distance to allow the streamer to straighten after every turn. The target is subdivided into“bins,” or small areas that are treated as reflection points for the purpose of processing the data. Most marine seismic projects acquire data at a range ofazimuths depending on the offset, or source-receiver distance. Azimuth (top) is the angle at the source array between the sail line and the direction to agiven receiver. For a few receivers near the head of the streamers, offsets are short and azimuths are large, but because the length of the streamers is somuch greater than the streamer spread, most of the seismic rays travel at small azimuth, or nearly parallel to the sail line.

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Spring 2007 29

The two main advantages of this arrangementof sources and receivers are efficiency inacquiring data over most subsurface targets—the marine seismic industry has built itselfaround this method—and the ability to obtainadequate images through standard processing.The disadvantages become clear when surveyingin problematic areas or under suboptimalcircumstances. Images may be faint orimpossible to interpret. Noise generated in thestreamers from weather and sea conditions cancontaminate the seismic record at all levels. Tomake matters worse, platforms and otherstructures can obstruct the path of surveyvessels, creating gaps in coverage that must befilled by additional shots and survey time. Andclose alignment between source and receiverarrays limits azimuthal coverage, meaning thereservoir is illuminated from only one direction.7

The Q-Marine single-sensor marine seismicsystem, introduced in 2000, has overcome severalof these limitations.8 Instead of recording signalsfrom grouped receivers, the Q-Marine systemrecords signals from individual receivers. Thisimproves spatial sampling of both the noise andthe desired wavefield, leading to several advan -tages over conventional acquisition. Q-Marinesurveys have, on average, broadened band widthby 40% compared with grouped-receiver tech -nology, thus increasing the resolution of seismicimages. Streamer noise can be adequatelysampled, allowing signal-processing techniquesto suppress it without harming signal bandwidth.This allows high-quality seismic data to beacquired even in poor weather, thereby reducingweather-related downtime.

Additional enhancements, such as repeat -able, calibrated sources, and the ability toposition streamers and steer them with highaccuracy and repeatability, have led to seismicimages with greater resolution. However, in someareas, further improvements are required.

New Directions in Seismic SurveysMost marine seismic surveys—including Q-Marine surveys—acquire data along a narrowazimuth, and so illuminate the target fromessentially one direction. If all subsurface layerswere flat and smooth, narrow-azimuth surveyswould deliver adequate images. However, inareas of E&P interest, subsurface targets andtheir overburden are rarely flat and smooth. Thedisadvantage of narrow-azimuth illumination inthese cases can be shown by analogy. Shining abeam of light on an irregular landscape produces

shadows behind mountains and within canyons.But, if the light shines from a different direction,areas that were in shadow become illuminated.

Although they are called narrow-azimuthsurveys, most marine surveys acquire seismicdata at a range of azimuths depending on theoffset, or source-receiver distance. For a fewshort offsets, the azimuth can be quite large, butfor most offsets, azimuths fall within a narrowrange—about 10° on either side of the sail line.Because the short-offset, large-azimuth tracesare not acquired in great number, they do notcontribute much to the image computed usingstandard processing. Thus, a target covered bysuch a survey is essentially illuminated by raysfrom a narrow range of azimuths, causing poorsignal-to-noise ratio and suboptimal seismicresolution. Most narrow-azimuth survey designsattempt to compensate for the lack of azimuthalrange by redundant sampling of the samesubsurface point, or bin.9 Increasing the fold, orthe number of traces per bin, is one way toincrease signal-to-noise ratio.

A particular type of noise that plagues allseismic surveys is called a “multiple.” Multiplesare reverberations between interfaces with highacoustic-impedance contrasts, such as betweenthe sea surface and sea bottom, or between theEarth’s surface and the bottom of a layer of

unconsolidated rock (above). They appear aslater arrivals on a seismic section, and thus areeasy to confuse with deep reflections. Becausemultiples have velocities that can be slower than,the same as, or faster than the desired signal,and can have frequency content higher than thatof the desired signal, they are difficult tosuppress through filtering and stacking.10

Significant efforts in surface-related multipleelimination (SRME) have led to processingtechniques that improve data quality, butmodeling has shown that even greaterimprovement in multiple attenuation can berealized by increasing azimuthal coverage.11

5. “Why Norwegian Seismic Is Still Running in AndersFarestveit’s Direction,” First Break 24 (December 2006):11–14.

6. Vermeer GJO: 3–D Seismic Survey Design. Tulsa: Societyof Exploration Geophysicists, 2002.

7. Azimuth is the bearing from the source to the receiver. 8. Christie P, Nichols D, Özbek A, Curtis T, Larsen L,

Strudley A, Davis R and Svendsen M: “Raising the Standards of Seismic Data Quality,” Oilfield Review 13,no. 2 (Summer 2001): 16–31.

9. A bin is the area on the target surface, typically 25 m by25 m [82 ft by 82 ft], to which seismic traces are assignedaccording to their common midpoint (CMP).

10. Stacking is the summation of signals, and is performed toenhance signal-to-noise ratio.

11. Regone C: “Using 3D Finite-Difference Modeling toDesign Wide Azimuth Surveys for Improved SubsaltImaging,” Expanded Abstracts, 75th SEG Annual International Meeting and Exposition, New Orleans(October 1–6, 2006): 2896–2900.

> Multiple reflections, or multiples. After leaving the source, seismic energycan reflect several times before arriving at the receiver. Unlike the others,the ghost multiple travels upward before reflecting. Energy from multiplesadds noise to seismic recordings.

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The azimuthal coverage of a survey can beincreased in several ways. One way is to repeat astandard survey at one or more azimuths,creating a multiazimuth survey (above).Multiazimuth surveys acquired in this wayincrease fold as well as azimuthal coverage. Onesuch survey has been acquired over the NileDelta in the Mediterranean Sea.12

Wide-Azimuth SurveysAnother way to increase azimuthal coverage in awider swath above the target is to displace theseismic source from the sail line of the streamervessel, in a wide-azimuth survey (WAZ). Wide-azimuth surveys require at least two sourcevessels in addition to the streamer vessel, andsome may be acquired with multiple streamervessels to improve acquisition efficiency.

The improvement that WAZ acquisition bringsto subsalt illumination can be seen in a modelingexample, in which a flat, horizontal target beneatha complex salt structure is probed by both narrow-

and wide-azimuth surveys (next page). In thenarrow-azimuth case, the number of hits, or timesthat seismic energy reaches a point on the target,is everywhere lower than in the wide-azimuthcase. In both cases, some portions of the target are not hit at all, but there are fewer of these misses in the wide-azimuth case. In addition tothis basic ray-tracing method, finite-differenceand wave-equation modeling are also used inillumination studies.

In 2001, in the Norwegian North Sea, BP andPetroleum Geo-Services (PGS) tested the wide-azimuth concept including high fold and usingmultiple vessels; earlier surveys had acquireddata in multiple directions.13 The results of the2001 survey showed improved noise attenuationwith increased azimuthal coverage. Since then,the method has grown in complexity and hasseen practical application. BP conducted thefirst Gulf of Mexico WAZ survey with seismiccontractor Veritas over the Mad Dog field in 2004and 2005.14

In 2006, Shell Exploration acquired a WAZtowed-streamer survey with WesternGeco over adeep objective below a complex salt structure ina deepwater area of the Gulf of Mexico.15 Theprospect is located in 3,800 ft [1,160 m] of water,and the discovery well was drilled to a total depthof 29,414 ft [8,965 m].

The survey design attempted to satisfy severalseemingly conflicting objectives: full illumi na -tion, optimal noise suppression, easy processingand low cost. Achieving these required a widerange of azimuths to illuminate targets under thesalt, relatively uniform sampling, minimization ofinefficiencies—such as over-redundancy insampling—and consideration of practicallimitations, such as the number of vesselsavailable for the survey and the number ofstreamer passes.

Four parameters are critical for WAZ surveydesign. First is the maximum crossline offset,which is the greatest separation between sourceand receiver in the crossline direction—

30 Oilfield Review

> Traditional and new acquisition geometries (bottom) and azimuth-offset distribution plots (top). One way to plot azimuth-offset distribution is as a “rosediagram.” The number of traces recorded at a particular azimuth-offset pair is plotted by color, with offset corresponding to the distance from the centerand azimuth corresponding to the angle from the top of the circle. Colors range from purple and dark blue for a low number of traces, to green, yellow andred for a high number of traces. From left to right: Traditional marine surveys are acquired in one azimuth and produce data with a narrow azimuth-offsetdistribution. Multiazimuth surveys are acquired in multiple directions, and have azimuth-offset distributions clustered along azimuths associated with thesurvey sail lines. Wide-azimuth surveys are acquired in a single direction, but with additional source vessels, increasing the azimuth for many offsets.Rich-azimuth surveys combine the concepts and advantages of multiazimuth and wide-azimuth surveys. (Adapted from Kapoor et al, reference 21.)

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Spring 2007 31

perpendicular to the inline, or streamer,direction. Second is the source-line interval,which is the distance between adjacent sourcelines. Third and fourth are survey size andnumber of vessels. The maximum crossline offsetand the source-line interval are determined fromsynthetic modeling and migration of syntheticdata.16 Illumination of the target and successfulattenuation of multiples are the main criteria forassessing the modeling results, which must alsoinclude deterioration of the image caused bygaps created when the streamers avoid surfaceobstructions, and feathering, or streamerdeviation caused by strong currents.

After evaluating several survey geometries,Shell selected a program comprising two dual-source vessels and one streamer vessel towingeight receiver cables spaced 150 m apart, for aneffective streamer swath of 1,200 m [3,937 ft].17

One source vessel sailed alongside the streamervessel, but offset 100 m [328 ft] from the outsidestreamer, while the second source vessel sailed

12. Keggin J, Benson M, Rietveld W, Manning T, Cook P and Page C: “Multi-Azimuth 3D Provides RobustImprovements in Nile Delta Seismic Imaging,” FirstBreak 25 (March 2007): 47–53.Michell S, Summers T, Shoshitaishvili E, Etgen J,Regone C, Barley B, Keggin J, Benson M, Reitveld Wand Manning T: “Multi-Azimuth and Wide AzimuthTowed Streamer Acquisition for Subsalt Imaging in theGulf of Mexico and Egypt,” paper OTC 18829, presentedat the Offshore Technology Conference, Houston,April 30–May 3, 2007.

13. Widmaier M, Keggin J, Hegna S and Kios E: “The Use of Multi-Azimuth Streamer Acquisition for Attenuation of Diffracted Multiples,” Expanded Abstracts, 72nd SEGAnnual International Meeting and Exposition, Salt LakeCity, Utah, USA (October 6–10, 2002): 89–93.Houllevigue H, Delesalle H and de Bazelaire E:“Enhanced Composite 3D Cube Derived from Multi-azimuth 3D Marine Acquisition,” Expanded Abstracts,61st European Association of Geoscientists andEngineers Conference and Exhibition, Helsinki, Finland (June 7–11, 1999). French WS: "Circular Seismic Acquisition System," USPatent No. 4,486,863 (December 4, 1984).

14. Threadgold IM, Zembeck-England K, Aas PG, FontanaPM, Hite D and Boone WE: “Implementing a WideAzimuth Towed Streamer Field Trial: The What, Why and Mostly How of WATS in Southern Green Canyon,”Expanded Abstracts, 76th SEG Annual InternationalMeeting and Exposition, New Orleans, (October 1–6,2006): 2901–2904.

15. Corcoran C, Perkins C, Lee D, Cook R, Kapoor J andMoldoveanu N: “Wide-Azimuth Streamer Acquisition forGulf of Mexico Subsalt Imaging,” paper OTC 19071,presented at the Offshore Technology Conference,Houston, April 30–May 3, 2007.Corcoran C, Perkins C, Lee D, Cattermole P, Cook R andMoldoveanu N: “A Wide-Azimuth Streamer AcquisitionPilot Project in the Gulf of Mexico,” The LeadingEdge 26, no. 4 (April 2007): 460-468.

16. Corcoran C, Perkins C, Lee D, Cattermole P, Cook R andMoldoveanu N: “Wide-Azimuth Streamer Acquisition forGulf of Mexico Subsalt Imaging,” Expanded Abstracts,76th SEG Annual International Meeting and Exposition,New Orleans (October 1–6, 2006): 2910–2914.

17. Corcoran et al, reference 16.

> Effect of narrow-azimuth and wide-azimuth acquisition on subsalt illumination. A complex butrealistic salt body (top), defined by its top (gold) and bottom (pink), overlies a target horizon (purple).Salt overhangs are in green. Shotpoints for both surveys are in the black rectangle. The narrow-azimuth acquisition hit map (middle) shows the number of traces that reach the target horizon. Thewide-azimuth hit map (bottom) shows more seismic traces reaching the target horizon, with fewerareas of no illumination (white).

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behind the streamers, offset from the first sourcevessel by 450 m [1,476 ft] (above). Then, whilethe source vessels repeated the same sourcelines, the streamer vessel performed additionalpasses at 1,400-m and 2,600-m [4,593-ft and8,530-ft] offsets from the original source line,and repeated those offsets again on the otherside of the source line. Each source line wasacquired six times. After this coverage for onesource line was completed, the entire processshifted 900 m [2,952 ft] to the next source line,and was repeated. The azimuth-offset plot forthis wide-azimuth survey displays a muchbroader distribution than for a narrow-azimuthsurvey (next page, top).

Data from this wide-azimuth pilot surveyunderwent initial processing, consisting of onlycoherent-noise attenuation and common shot-

gather migration using a preexisting velocitymodel.18 This dataset, with only basic processingapplied, was compared with more fully processedWesternGeco narrow-azimuth data from amulticlient survey covering the same area (nextpage, bottom).19 The narrow-azimuth surveyprocessing included coherent-noise attenuation,SRME multiple suppression and the same wave-equation migration as the WAZ survey. Evenwithout additional multiple suppression, theWAZ survey produced a clearer subsalt picturethan the narrow-azimuth survey, leading to moreconfident assessment that the reflections werecoming from subsalt layers rather than multiples.

The improvement in clarity is most obvious onthe left side of the section, where sedimentstruncate against the salt keel in the middle of thesection. The WAZ data convinced interpretersthat significant subsalt events continue updip

toward the salt keel, and that these events arenot multiples.20

Shell concluded that while not all areasbelow the salt were illuminated, the WAZ surveyimproved the image of subsalt sedimentarystructure in most places. The dominant multipleswere removed without specific processing.Depopulation tests to see if adequate resultscould be achieved with less data showed that in

32 Oilfield Review

18. Wave-equation migration uses a velocity model andvarious solutions to the wave equation that describepropagation of waves through rock. The objective is to redistribute reflected seismic energy from itsassumed position at the source-receiver midpoint to its true position.

19. Multiclient surveys are surveys acquired by seismiccontractors over unlicensed areas, then made availableto multiple clients. Partial funding for multiclient surveysmay be provided by one or more E&P companies.

20. A salt keel is what remains of the root of an intrudingsalt body after the root has detached itself from theparent salt layer.

> Acquisition of the Shell wide-azimuth survey. With two dual-source vessels and one streamer vessel towing eight receiver cables, six passes were made at varying offsets for each source line (top). For the first pass, the forward source vessel sailed along the source line, while the streamer vesselsailed with the nearest streamer 100 m away. The rear source vessel sailed 450 m from the source line. For the second pass, the source vessels repeatedthe same source line, and the streamer vessel performed another pass at a 1,400-m offset from the original source line, and made a third pass at a 2,600-moffset. The vessels then repeated the pattern again on the other side of the source line (Pass 4, Pass 5 and Pass 6). The combination of those six runsconstituted the acquisition of one source line. After acquisition of that source line, the vessels moved to the next source line, offset by 900 m (bottom left).

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the deep subsalt areas, images acquired byremoving every other source line were almost asgood as the full dataset. These tests alsoindicated that data acquired from sources infront of the streamers provided better subsaltimaging than data acquired from the sources

behind the vessel, where streamer feathering hasgreater negative impact. This information couldhelp in the design of future WAZ surveys.

The two-phase wide-azimuth study wasdesigned to demonstrate the value of WAZtechnology in exploring complex subsalt settings.

Following the successful imaging results fromthe first phase, the second phase was cancelledand Shell Exploration moved to underwriteacquisition of a large multiclient WAZ explora -tion survey in the Gulf of Mexico.

> The azimuth-offset distribution (left) and survey parameters (right) for the Shell wide-azimuth survey. The survey acquired abroader range of azimuths compared with a narrow-azimuth survey.

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> Comparison between images acquired with narrow-azimuth (left) and wide-azimuth (right) methods. The narrow-azimuth data were fully processed with noise-attenuation, multiple-suppression and migration steps. The wide-azimuth data were only migrated, and with the same velocity model as thenarrow-azimuth data. The wide-azimuth image shows clearer subsalt reflections, especially on the left side of the section. [Adapted from Corcoran et al,reference 15 (April 2007).]

Salt keel

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Using knowledge gained from modeling andearlier WAZ surveys, WesternGeco has designedand acquired two large WAZ surveys formulticlient use (left). These surveys incorporateddesign improvements such as crosslinereciprocity—sail lines in opposing directions—and source vessels at the forward rather than aftend of the streamers.21 They also use widercrossline offsets for better signal-to-noise ratio,multiple attenuation and illumination.

The first survey, completed in 2006, covered222 Gulf of Mexico blocks, or 5,183 km2

[2,002 mi2], and deployed three single-sourcevessels. Ten 7,000-m [22,967-ft] streamers wereused in a 1,200-m [3,936-ft] spread width, andsail lines were run in reciprocal directions. Thesecond survey, completed in 2007, covered252 blocks, or 5,895 km2 [2,278 mi2], anddeployed four single-source vessels, includingsingle sources on two streamer vesselsinterleaving in two opposing directions.

The first multiclient WAZ survey providesimproved images compared with narrow-azimuthsurveys acquired over the same area. Withminimal processing, the new images showenhanced clarity and illumination, especially inareas beneath salt overhangs (below).

The third and fourth phases of the multiclientGulf of Mexico WAZ project will cover more than10,000 km2 [4,000 mi2] starting in May, 2007. Thegoal is to produce is a quick-look wave-equationmigrated volume through onboard processing,allowing customers to meet lease sales deadlines.

34 Oilfield Review

> Two large multiclient wide-azimuth surveys acquired by WesternGeco in the Gulf of Mexico,incorporating lessons learned from earlier surveys. The Phase 1 survey, completed in 2006, wasacquired with two source vessels and one streamer vessel (top). Phase 2, completed in 2007, usedtwo source vessels and two streamer vessels (bottom). In both Phase 1 and 2, each streamer vesselalso also carried a single source.


New OrleansHouston

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> Comparison between the first multiclient wide-azimuth survey and a narrow-azimuth survey. The narrow-azimuth survey (left) has had full processingwith multiple suppression, while the multiazimuth survey (right) has had only basic migration processing. The multiazimuth image shows better illuminationbelow salt overhangs and in deep sediments.

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Spring 2007 35

Rich-Azimuth SurveysAzimuthal coverage can be further enhanced bycombining the multiazimuth and wide-azimuthconcepts in what is called a rich-azimuth survey(RAZ). BHP Billiton first implemented this typeof acquisition in 2006 over the Shenzi field in theGulf of Mexico, a 2002 discovery in water depthsup to 4,300 ft [1,300 m] approximately 120 miles[190 km] from the coast of Louisiana (right).22

The field comprises Green Canyon Blocks 609,610, 653 and 654. Development drilling willassess recoverable reserves, which are estimatedat 350 to 400 million bbl [56 to 64 million m3].23

Coventurers in the project are Hess Corporationand Repsol YPF.

The Shenzi discovery well was drilled to atarget identified by 3D seismic data, but the firstappraisal well encountered subsurface layers atunexpected depths. New seismic data withhigher signal-to-noise ratio and resolution wererequired to build a more reliable subsurfacemodel that would reduce the risk of futuredrilling. A survey design and evaluation studyhelped BHP Billiton and WesternGecogeophysicists conclude that a rich-azimuthsurvey was the best choice for the Shenzireservoir. Important factors in this decision werethe reservoir structural complexity, strongcurrents, rig activity and platforms.

The RAZ survey, the world’s first, wasacquired with one streamer vessel equipped witha source and two source vessels shooting along

three azimuths, 30°, 90° and 150° (below). Thesurvey plan allowed each shot location to berepeated at least three times.

In another world’s first, the streamer vesselcontinued recording during tight vessel turns.Shooting and recording while turning improve

21. Kapoor S, O’Briain M, Desta D, Atakishiyev I andTomida M: “Subsalt Imaging—The RAZ/WAZExperience,” prepared for presentation at the 77th SEGAnnual International Meeting and Exposition, San Antonio, Texas, September 23–28, 2007.

22. Howard MS and Moldoveanu N: “Marine Survey Designfor Rich-Azimuth Seismic Using Surface Streamers,”

Expanded Abstracts, 76th SEG Annual InternationalMeeting and Exposition, New Orleans (October 1–6,2006): 2915–2919.

23. BHP Billiton to Develop Shenzi Oil and Gas Field in Gulfof Mexico, http://www.bhpbilliton.com/bb/investorsMedia/news/2006/bhpBillitonToDevelopShenziOilAndGasFieldInGulfOfMexico.jsp (accessed March 2, 2007).

> Location of the Shenzi field survey (left) and acquisition parameters for therich-azimuth survey (right).

Shenzifield

New Orleans

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> Survey plan for the world’s first rich-azimuth survey, acquired over the Shenzi field (left). The sail lines and platform obstructions (pink dots) are drawn to illustrate the general concept and differ from the actual survey. The violet square represents source coverage from E-W lines, and the black hexagonrepresents source coverage from three directions. The survey acquired data with a rich azimuth-offset distribution (right).

Num

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operational efficiency and reduce nonproductivetime. Typically, vessels extend their sail lines andturn well outside the boundary of the survey, sothat the streamers are straight and at the properseparation by the time the vessel reenters theboundary. This practice adds time to the surveyacquisition—an extra two hours per turn(below). Usually, no data are acquired during the

turn, because the streamers do not track cleanlyaround the turn and the receiver positions arenot accurately calculated. Also, towing through acurve causes too much noise for useable data tobe acquired.

With the Q-Marine system, streamers can bepositioned and steered so that they maintainspacing throughout the turn. Also, recording data

from individual hydrophones, instead of groupingbefore recording, allows removal of noise fromturning, which resembles bad-weather noise.These features promote acquisition of valuabledata during periods that would normally benonproductive. Acquiring additional data on theedges of the Shenzi survey increased the areathat could be imaged effectively and improvedthe images of the target near the boundary of thesurvey area.

Comparison to a fully processed conventionalnarrow-azimuth survey showed that the Q-Marine rich-azimuth survey with basicprocessing reduced noise artifacts and producedclearer illumination of the base of the salt, andsubsalt reflections, than the fully processed narrow-azimuth survey (next page, top).24

Reflections could even be identified within thesalt. However, the greatest improvement was inreflections deep below the salt. BHP Billitongeophysicists are now able to interpretstructures in zones that are better illuminated.

According to the survey plan, the RAZ surveywould have taken 105 days, compared with aconventional survey that would have taken72 days to cover the same area. As shot, theShenzi RAZ survey took just 88 days, plus 12 daysin mobilization, and delivered six times the dataof a conventional survey. The time savings arosefrom several factors. Shooting in three directionswith the wide-azimuth acquisition made itunnecessary to undershoot obstacles, andminimized the time required to shoot infill lines.The vessel crews experienced almost no weatherdowntime, because the streamer cables weretowed deep, at 12 m [39 ft], and the Q-Marinesingle-sensor recording adequately sampled anyweather-related noise. Following the success ofthe first RAZ survey, BHP Billiton is preparing toacquire another.

WesternGeco experience in WAZ and RAZsurveys demonstrated several benefits of wide-azimuth and rich-azimuth acquisition. Improvedattenuation of multiples and other coherentnoise provides increased signal-to-noise ratio ofsubsurface events. Raypaths from differentazimuths result in better reservoir illumination,and repeatability of shots in the same locationmakes migration processing highly efficient.Additionally, acquiring data while turningincreases efficiency, and is a practice thatWesternGeco expects to extend to conventional3D Q-Marine surveys.

36 Oilfield Review

> Shooting and recording while turning, for improved operational efficiency. In traditional surveys (top left), each sail line (dashed line) is extended to make sure the streamers are straight for allshots. This additional line length at the beginning and end of each turn adds hours to the turningtime. The Q-Marine system allows streamers to stay in position throughout the turn (green line), sodata acquisition during turning is possible. The quality of data acquired while turning is comparableto that acquired along sail lines (top right). Data acquired in the turns contribute to the overall image of subsurface reflectors and fit smoothly with data acquired by straight streamers (bottom).

1,500m-radiusFinish shooting

Start shooting

Line Change Analysisfor Single-Vessel Option

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Spring 2007 37

Towing-Depth Trade-OffsA completely different approach to improvingseismic signal involves deploying sources andstreamers differently to more fully sample boththe noise and desired energy fields. As outlinedearlier, acquiring marine seismic data typicallyinvolves towing sources and receiver cables atconstant depths specified by the survey design.Selecting the depths calls for consideration ofseveral factors. One of these is the limiting effectof the source and receiver depths on thefrequency content of the seismic energy that canbe recorded. Understanding how source andreceiver geometry affects signal-to-noise leveland frequency content requires examining the way energy propagates from the towed source to the receiver cable, and especially hownear-surface multiples add noise and reducesignal (right).

Energy radiates from the seismic source in alldirections—not only downward but also upward.The negative acoustic-impedance contrast at thesea surface causes the upgoing wavefield toreflect downward with a reversed polarity.25

Because of this polarity reversal, the wavereflected at the sea surface, called the sourceghost, and the direct, downgoing, wavedestructively interfere to the extent that atcertain frequencies, the amplitudes cancel. The

result is a downward propagating wavefield thatis deficient in energy at certain frequencies. Thefrequencies at which these deficiencies occur—at which amplitude falls to zero—are called the

source-ghost notches, and are related to thedepth of the source. The greater the depth of thesource, the lower the first, nonzero source-ghostnotch frequency.

24. Howard M: “Marine Seismic Surveys with EnhancedAzimuth Coverage: Lessons in Survey Design andAcquisition,” The Leading Edge 26, no. 4 (April 2007):480–493.

25. Polarity of a seismic signal refers to the direction of itsamplitude in a recorded seismic trace. Negative andpositive amplitudes have opposite polarity.

> An image from the Shenzi rich-azimuth survey, showing enhanced clarity of subsalt events relative to a more fully processed narrow-azimuth survey. Thenarrow-azimuth survey (left) shows some indications of dipping layers beneath the salt, but the rich-azimuth image (right) illuminates subsalt layers clearly.The survey configurations for each survey are adjacent to the seismic images. (Adapted from Howard, reference 24.)

Narrow-Azimuth, Full Processing Rich-Azimuth, Basic Processing

Bottom of salt Bottom of salt

> Ghost multiples, or reflections at the underside of the sea surface. Energytraveling upward from the source reflects at the sea surface with a polaritychange, and interferes destructively with energy emanating downward from the source. Similarly, reflected energy traveling upward from thesubsurface can reflect at the sea surface before being recorded at thestreamer cable as a receiver ghost. These reflections also interferedestructively with upgoing reflected energy, causing recorded amplitude to fall to zero at certain frequencies that depend on the depths of sourceand receiver.

Seafloor

SourceSourceghost

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Similarly, energy returning from a deepreflector travels upward toward the receivercable and also reflects off the sea surface,interfering destructively with energy travelingdirectly from the deep reflector to the receiver.This interference causes cable-ghost notches at several frequencies (middle right). Thecombina tion of the source- and cable-ghostnotches leads to a complex amplitude spectrumthat produces gaps in the available seismicsignal. The maximum frequency used inprocessing is usually limited at the frequencycorresponding to the first receiver notch, and theminimum frequency is limited by the acquisitionfilter, which is typically 3 Hz.

Because the objective is to acquire data of thegreatest bandwidth and highest frequencypossible, the source and streamer are usuallytowed at shallow depth, pushing the first,nonzero notch frequency higher. However,shallow towing has disadvantages. Wind, wavesand shallow currents add noise to the acquiredsignal, and the need to keep noise to a minimumcan restrict acquisition to seasons with goodweather. Also, shallow towing attenuates theextremely low frequencies needed for inversion,a processing technique that extracts acousticimpedance and other rock properties fromseismic data.26

Another disadvantage to the lack of lowfrequencies is the diminished probing power ofseismic waves. Because depth of penetration isrelated to seismic wavelength, the lack of lowfrequencies limits the depth to which seismicenergy propagates.

Increasing the towing depth allows dataacquisition in a quieter environment, extendsthe acquisition season and extends the band -width to lower frequencies. This allows imagingat greater depth, but decreases the maximumfrequency of data that can be recorded, and sodecreases the overall image resolution.

Until recently, survey planners had tosacrifice resolution and high frequencies fordepth of penetration and a quiet acquisitionenvironment, or vice versa. They were forced tochoose between towing shallow, deep, or at some intermediate depth. However, a reemergingacquisition technology called “over/under”allows companies to enjoy the advantages of both shallow and deep towing without the drawbacks.27

Over and UnderThe idea of towing one shallow streamer alongwith one deep streamer—one over and oneunder—has been around for more than50 years.28 Practical application of the methodwas attempted in the 1980s to reduce weather-related noise and downtime.29 A key benefit ofthe over/under method is the increased band -width obtained from the ability to fill the nonzeroghost notches through combination of the overand under streamers, while still retaining thelow-frequency benefit of deep towed streamers.Also, in theory, the vertical separation of twolinear arrays of receivers allows the upgoingseismic wavefield to be separated from thedowngoing waves, facilitating the suppression ofsurface-related multiples.30

38 Oilfield Review

> Modeling the effect of streamer depth on frequency content of therecorded signal. Towing streamers at a shallow depth, 8 m (red dashed line),produces signals up to 93 Hz before the first nonzero-frequency notch cutsthe signal amplitude to zero. Towing streamers deep, at 30 m (green),produces signals up to 25 Hz before the first notch cuts signal amplitude tozero. (Adapted from Moldoveanu et al, reference 27.)

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> Over/under streamer configuration for the Chevron 2D survey inthe Gulf of Mexico. An over/under pair of streamers (darker blue)was towed at 18 and 25.2 m, along with position-monitoringstreamers at either side at 18-m depth, and an experimental-controlstreamer at 7.2 m. Sources were deployed at 5 and 10 m.


Spring 2007 39

However, the success of this acquisitiongeometry in removing the ghost notches from theseismic data relies on keeping one streamerdirectly below the other, in one vertical plane allalong the streamer length. Achieving thisconfiguration was not feasible with the towed-streamer technology of the 1980s, and so the ideawas not put into practice for many years. In spiteof these practical limitations, scientists continuedto develop wavefield-separa tion techniques foreventual application.31

Recently, acquisition technology caught upwith processing advances. The Q-Marine systemis capable of steering pairs of streamers in avertical plane with sufficient accuracy for theover/under method to succeed. To demonstratethe feasibility and promise of the method,Chevron and WesternGeco performed a 2Dexperiment over the Genesis field in the Gulf ofMexico in 2004.32

The acquisition plan for the 2D line called forstreamers to be towed at 18 and 25.2 m [59 and82.7 ft]. However, to accurately calculatereceiver positions, another two streamers weredeployed, one on each side of the over/understreamers, at a depth of 18 m (previous page,bottom). One additional streamer was towed at7.2 m [23.6 ft], directly above the over/underpair, to acquire conventional Q-Marine data as anexperimental control. All five streamers wereequipped with Q-Fin marine seismic streamersteering devices and a complete acousticnetwork to allow accurate positioning of thecentral streamers. The recording bandwidth wasincreased to record from 1.5 to 200 Hz to includethe anticipated low-frequency response.

Throughout acquisition, monitoring of thevertical and horizontal separations of thestreamers showed that variation in the 7.2-mvertical separation averaged less than 10 cm[4 in.], and the horizontal, or crossline,separation was always less than 6 m [20 ft]—believed to be adequate for separation of theupgoing and downgoing wavefields.

Comparison between the control dataset andthe upgoing wavefield from the over/under lineshows improved low-frequency response andhigher signal-to-noise ratio for the over/underdata (above right). The deep sediments in basinsbounded by faults and salt diapirs are muchclearer in the over/under line, as are the near-vertical flanks of the salt and highly dipping features throughout the section. Thebandwidth extension to lower frequencies allowsdeeper penetration of seismic energy and betterimaging of deep reflections than seen in thecontrol dataset.

26. Low-frequency information is needed for inversion ofseismic data because typically, the seismic datathemselves provide only high-frequency information,such as relative changes in reflectivity or acousticimpedance at each layer boundary. Low-frequencyinformation, typically derived from checkshots orintegrated sonic logs, provides the baseline from whichthe high-frequency data vary. By combining both low-and high-frequency information, absolute changes inrock properties may be calculated. Because seismicinversion requires a combination of seismic and welldata, it usually cannot be performed reliably in theabsence of wells. However, if seismic data could beacquired with low-frequency content intact, inversioncould be carried out in more areas.

27. Moldoveanu N, Combee L, Egan M, Hampson G, Sydora Land Abriel W: “Over/Under Towed-Streamer Acquisition:A Method to Extend Seismic Bandwidth to Both Higherand Lower Frequencies,” The Leading Edge 26, no. 1(January 2007): 41–42, 44–46, 48, 50–54, 56–58.

28. Haggerty PE; “Method and Apparatus for CancelingReverberations in Water Layers,” U.S. PatentNo. 2,757,356, July 21, 1956.

29. Brink M and Svendsen M: “Marine Seismic ExplorationUsing Vertical Receiver Arrays: A Means for Reductionof Weather Downtime,” Expanded Abstracts, 57th SEGAnnual International Meeting and Exposition, New Orleans (October 11–15, 1987): 184–187.

30. Sonneland L, Berg LE, Eidsvig P, Haugen R, Fotland Band Vestby J: “2-D Deghosting Using Vertical ReceiverArrays,” Expanded Abstracts, 56th SEG AnnualInternational Meeting and Exposition, Houston(November 2–6, 1986): 516–519.

31. Posthumus BJ: “Deghosting Using a Twin StreamerConfiguration,” Geophysical Prospecting 41, no. 3(April 1993): 267–286.

32. Moldoveanu et al, reference 27.

> Improved low-frequency content and signal penetration from over/under data (bottom) comparedwith a traditionally acquired control survey (top). The migrated data from the upgoing wavefield of the over/under line show better imaging of steeply dipping interfaces and improved low-frequencycontent in signals from deep sediment layers. (Adapted from Moldoveanu et al, reference 27.)

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Spectral analysis of data acquired from all three central streamers demonstrates thatthe upgoing wavefield also has better high-frequency response than data from any of thestreamers individually, and that the low-frequency response is similar to that of thedeepest streamer (above).

Another innovation that was tested in thisover/under survey was the concept of over/undersources.33 The airgun source arrays were towed at5- and 10-m depths and their signals wererecorded by the streamer towed at 7.2-m depth.After the over/under data were processed toseparate the upgoing and downgoing wavefields,comparison between the migrated upgoing imageobtained from the over/under source combin -ation and the migrated image from the uppersource alone showed an improvement in low-frequency content and in the signal-to-noiseratio at deep reflectors.

After these successful tests, Chevron decidedto apply over/under streamer and sourcetechnology to a large project in the northeastAtlantic, east of the Faroe Islands and west of theShetland Islands.34 Water depths in the Faroe-Shetland Channel exceed 1,000 m [3,300 ft], andweather can be harsh. Also known as the West ofShetlands, this offshore UK region has seensignificant exploration success (above right).However, some prospective areas await betterdelineation with seismic imaging technology thatcan see through basalt layers that obscureunderlying structure.

Basalt is a highly attenuative medium, andalthough several geophysical methods have beenproposed to improve imaging through it, basaltremains an obstacle to hydrocarbon explorationin many areas.35 Its high seismic velocity bendsrays and prevents all but the lowest-frequencyseismic energy from penetrating.

In 2005, the vessel Western Pride completeda regional 2D over/under survey in this area.36

The survey objective was to improve thesubbasalt image compared with what could beproduced from a single-source, single-streameracquisition configuration. The two source depthswere 12 and 20 m [39 and 66 ft], and the twostreamer depths were 20 and 30 m [66 and 98 ft].The combination of the “over” source at 12 m andthe “over” streamer at 20 m was taken as theequivalent of what would have been recorded inconventional acquisition.

Compared with the image from the conven -tional acquisition, the over/under image showsfar richer low-frequency information beneath the basalt (next page, top). This allowsinterpretation of subbasalt structure withgreater confidence. Moreover, the deep-penetrating low frequencies are not generated atthe expense of high frequencies. A comparison ofshallow images shows that the over/undermethod produces sufficiently high frequencies toimage shallower objectives.

The improvement in bandwidth associatedwith over/under acquisition can be seen in acomparison of amplitude spectra for both the

signal and the noise extracted from a shallow and a deep window of the conventional and over/under datasets (next page, bottom). In theshallow window above the basalt, the over/underdata display a signal bandwidth from 2 to 60 Hz,while the conventional-data bandwidth is 5 to 37 Hz, where the notch can be seen. In the deepwindow, below the basalt, the over/under datahave a lower peak frequency than the conven -tionally acquired data. In general, the over/underdata have greater bandwidth and greaterseparation between signal and noise.

The over/under technique has also beentested in 3D, with equally positive results.37 Inthis case, a 67-mi2 [173-km2] survey was acquiredwith four pairs of over/under streamers over asubsalt play in the Gulf of Mexico. The 3Dexperiment demonstrated that the 3- to 55-Hzbandwidth achievable with conventionalacquisition could be increased to 2 to 63 Hz withover/under acquisition. The resulting migratedimages showed that the seemingly smallextension in bandwidth produced significantresults in imaging reflections below and withinthe salt.

40 Oilfield Review

> Comparison of amplitude spectra from the over/under data and theshallow-streamer, reference dataset. Amplitude spectra from the upgoingwavefield obtained from the over/under data (black) show a widerbandwidth than the shallow-streamer, reference data (green), the data fromthe “over” streamer (red) and the data from the “under” streamer (blue).The upgoing wavefield also has a better high-frequency response than any of the individual streamers, and has a low-frequency response similarto that of the deepest streamer. (Adapted from Moldoveanu et al,reference 27.)

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> The offshore UK region west of the ShetlandIslands, a deepwater hydrocarbon province withwater depths in excess of 1,000 m. Severalcompanies have had exploration success here,finding oil in the Clair, Schiehallion and Foinavenfields, among others (green and red). Many areasof potential hydrocarbon-bearing formations liebeneath basalt, which hinders deep penetration ofseismic energy.

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Spring 2007 41

More recently, over/under surveys have beenacquired elsewhere for similar reasons. In theBarents Sea, salt outcropping at the seafloorcreates a high acoustic-impedance contrast thatattenuates seismic energy. Offshore India, thehard sea bottom and deep basalt have madeimaging difficult in the past. The over/undermethod shows promise for imaging beneath andwithin carbonates and in other salt-proneprovinces, such as offshore West Africa.

33. Moldoveanu N: “Source Array for Use in Marine Seismic Exploration,” U.S. Patent No. 6,961,284,November 1, 2005.Moldoveanu N: “Vertical Source Array in MarineSeismic Exploration,” Expanded Abstracts, 70th SEGAnnual International Meeting and Exposition, Calgary(August 6–11, 2000): 53–56.

34. Hill D, Combee L and Bacon J: “Imaging Beneath BasaltUsing an Over/Under Towed-Streamer Configuration,”World Oil 227, no. 5 (May 2006): 55–61.Hill D, Combee L and Bacon J: “Over/Under Acquisitionand Data Processing: The Next Quantum Leap in SeismicTechnology?” First Break 24, no. 6 (June 2006): 81–95.

35. Kumar D, Bastia R and Guha D: “Prospect HuntingBelow Deccan Basalt: Imaging Challenges andSolutions,” First Break 22, no. 7 (July 2004): 35–39.

36. Hill et al, reference 34 (May 2006).37. Moldoveanu et al, reference 27.

> Over/under and conventional images from the Chevron West of Shetlands survey. This over/under survey towed pairs of both sources and streamers. The image produced from the resulting upgoing wavefield (top right) shows significantly more low-frequency information below the basalt than theconventional image (top left). The top of basalt is indicated by the yellow arrow. The generation of low frequencies does not decrease the high-frequencysignal content, as seen in a close-up view (in yellow boxes) of a shallow section above the basalt. The shallow section of the over/under image (bottomright) shows a high-frequency content similar to that seen in the shallow section of the conventionally acquired image (bottom left). [Adapted from Hill et al, reference 34 (June 2006).]

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> Comparison of signal and noise amplitude spectra from over/under (top) and conventionallyacquired data (bottom) from West of Shetlands. Spectral analysis of shallow data in a window from2.9 to 4.0 s demonstrates the wider bandwidth of the over/under data (top left) than the conventionalsurvey (bottom left). The over/under data exhibit a signal bandwidth from 2 to 60 Hz, while theconventional data contain signal from 5 to 37 Hz. Comparing signal content deeper, below the basalt,the over/under data (top right) show a peak at a lower frequency than the conventional data (bottomright). The greater bandwidth and larger separation between signal (blue) and noise (black) levelshelp produce higher resolution images with deeper penetration. [Adapted from Hill et al,reference 34 (June 2006).]

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Targeting Carbonate PorosityCarbonates pose another challenge to 3D seismicimaging. Like basalts, their high seismic velocitiesbend rays, hiding both their own internalstructure and that of underlying formations.

After the 2003 discovery of the Lobina fieldoffshore northeastern Mexico, Pemex needed ahigh-resolution 3D survey to assess and rankpotential drilling locations. The Lobina field isadjacent to the Arenque field, a 1968 discovery

that also would benefit from enhanced reservoirdescription. Low resolution caused by insuf -ficient frequency content limited the usefulnessof a 1996 3D survey.

A new survey, using the Q-Marine system, wasdesigned to capture a wider bandwidth andpreserve true amplitudes for inversion ofreservoir properties.38 Obstructions and shallowwater depths, ranging from 30 to 80 m [100 to260 ft], presented design challenges, but the

acquisition of the 320-km2 [124-mi2] survey wascompleted in just two months.

Initial processing indicated that the newsurvey doubled the maximum recordedfrequency compared with the 1996 survey,recording up to 60 Hz compared with the 30-Hzmaximum recorded in 1996. The increasedfrequency content significantly enhancedinterpreters’ ability to map key reservoir layers.

The objective was to identify high-porosityzones within two carbonate layers, primarily aJurassic limestone, and secondarily, a shallowerCretaceous carbonate target. The carbonatelayers themselves are high-velocity layers, but insome zones, high porosity causes a markeddecrease in seismic velocity.

Inverting the stacked seismic data allowedgeophysicists to obtain a trace-by-trace quanti -tative measure of acoustic impedance.39 Aftercalibration with acoustic impedances from sonicand density logs from 40 wells in the survey area,the seismic acoustic-impedance sections wereconverted to porosity sections, using an acoustic-impedance-to-porosity relationship from the wells.

The resulting porosity volume showed theinternal architecture of the best reservoir unitsand allowed Pemex to optimize drillinglocations in the Lobina and Arenque fields(left). Mapping maximum porosity between thetop and base of the reservoir let Pemexcalculate the volume of sweet spots. In thisexample, at the location of proposed ArenqueWell B, the high porosity in the lower reservoirmade this a high-priority target.

Another way to prioritize potential drillinglocations is by comparing the product of porosityand height for gross reservoir intervals (left).Comparing the porosity-height productcomputed at several wells with the porosity-height product computed from the seismic dataat the well locations shows a good correlation.These wells were not used in the inversion of theseismic data for porosity, and so the comparisonis an excellent test of the qualitative power ofthe inversion.

42 Oilfield Review

38. Salter R, Shelander D, Beller M, Flack B, Gillespie D,Moldoveanu N, Gonzalez Pineda F and Camara Alfaro J:“Using High-Resolution Seismic for Carbonate ReservoirDescription,” World Oil 227, no. 3 (March 2006): 57–66.

39. Salter R, Shelander D, Beller M, Flack B, Gillespie D,Moldoveanu N, Pineda F and Camara J: “The Impact ofHigh-Resolution Seismic Data on Carbonate ReservoirDescription, Offshore Mexico,” presented at theInternational Exposition and 75th Annual Meeting of the SEG, Houston, November 6–11, 2005.

> Porosity section produced by borehole-calibrated inversion of Q-Marineseismic data over the Arenque and Lobina fields, offshore Mexico. Color-coding highlights high-porosity zones in two carbonate reservoirs, allowingPemex to optimize locations of development wells. These results indicatedthat the proposed location of Arenque Well B would encounter highporosities in the lower carbonate, raising the priority of this well. Otherwells are indicated by black lines. Marker-horizon names are labeled on the left. (Adapted from Salter et al, reference 38.)

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> Correlation of the porosity-height product derived from inversion of seismicdata with that interpreted from measurements at well locations. Overall, theporosity-height product from seismic measurements (purple) comparesclosely with that calculated from logging measurements (blue). These resultsincrease confidence in the seismically derived porosity values. (Adapted fromSalter et al, reference 38.)

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Using the porosity-height attribute andmaximum-porosity maps, Pemex reduced thepriority of two drilling locations and gave higherpriority to two others. The seismic results wereavailable in time for a rig traveling to onelocation to be diverted to a preferred location.The Arenque Well B, drilled with the seismic-porosity results as a guide, produced oil andtested at 2,000 bbl/d [318 m3/d]. The seismicallyderived porosity results show excellentcorrelation with the measured porosity in thewell (right).

Reducing risk in development drilling is anapplication in which high-quality seismic dataplay a vital role. Many fields that were discoveredwith the help of exploration 2D or 3D surveyshave been further characterized by additional 3Dsurveys designed to identify optimal development-well locations. When 3D data are of superiorquality, they can be used to map propertieswithin reservoirs, increasing confidence in infill-drilling plans.

A Rich FutureThe basic 3D marine seismic survey thatrevolutionized exploration in the 1990s hasadvanced in many ways. New acquisition methodsthat enhance azimuthal coverage, such as wide-azimuth and rich-azimuth surveys, have provideda step-change improvement in difficult subsaltenvironments. These surveys deliver increasedsignal-to-noise ratio and improved reservoirillumination. The examples in this articledemonstrate the improvements possible with onlybasic processing. Full processing of the wide-azimuth data is in progress and is expected tosignificantly improve the results by applyingmultiple attenuation and an optimized velocitymodel for imaging. Through further applicationand experimentation, seismic practitioners expecteven more from WAZ and RAZ surveys, such asextension to carbonate and subbasalt exploration.Other potential benefits are improved velocitymodels for imaging, especially where anisotropy isinvolved, better characteri zation of fracturedreservoirs, geomechanical studies around planneddeepwater well locations and high-resolutionimaging of shallow drilling hazards.

The improvement in signal bandwidth andpenetration that comes with the over/undermethod of towing vertically aligned streamersand sources has helped illuminate deepstructures that previously were hidden. Thetechnique is a viable geophysical solution for

> Logging results from Arenque Well B, drilled to exploit the high-porosityzone identified by inversion of seismic data. Color-coding indicatesseismically derived porosity in two carbonate reservoirs. Well B targetedthe high-porosity zone in the lower carbonate (orange and yellow), justbelow the Csa marker (blue-green dot). The porosity calculated from welllogs is projected along the well trajectory, and shows good correlation withthe seismically derived porosity values in both reservoirs. During testing,the well flowed oil at a rate of 2,000 bbl/d. (Adapted from Salter et al,reference 38.)

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boosting resolution and low-frequency content inareas where conventional seismic methods fail.One future challenge for the over/under methodis to tow more streamers. In recent surveys,vessels have towed four pairs of streamers.Theoretically, a few WesternGeco vessels can toweight pairs, but this has not yet been attempted.Researchers are investigating still otherarrangements of streamers for next-generationover/under acquisition.

The ability to acquire high-fidelity seismicdata with single-sensor technology ensures thatcompanies have the optimal input data forinversion routines designed to output reservoirproperties, such as acoustic impedance, porosityand other rock and fluid characteristics. Thisallows interpreters to look inside reservoirs anddetermine where to place development wellswith greater confidence. Current inversionmethods require low-frequency information fromwell logs or well seismic surveys. However, assurface seismic acquisition methods—such asthe over/under technique—increase signal low-frequency content, inversion may becomepractical in areas far from existing wells.

As more companies reap the wealth of recent advancements in marine seismictechnology, they will discover not only more oiland gas, but also how to use seismic data toreduce risk, replace reserves, lower finding costs,decrease the number of development wells,optimize well placement and acceleratedevelopment programs. –LS


Exploration Process Data

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