25-Reservoir Management Using 3-d Seismic Data

8/2/2019 25-Reservoir Management Using 3-d Seismic Data

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R e s e r v o i r m a n a g e m e n tu s in g 3 -D se ism ic d a t a

T e geologic detail needed to properly develop most hydrocar-bon reservoirs substantially exc&s the detail required to findthem_ This obvious but compelling precept has fuel& the steadi-ly increasing application of 3-II seismic analyses to reservoirmanagement. A measure of the increase is that 3-D surveys nowaccount for half of the seismic activity in the offshore Gulf ofMexico and Noti Sea, and the percentage has been rising steadi-ly year by year since commercial 3-D surveys were first shot inthese areas in 1975 (Figure 1). Threedimensional seismic survey-ing in other offshore areas and on land likewise is growing rapid-ly_ The Fall 1 9 8 8 E G Distinguished Lecture addressed the generalsubjEt of rnmaging reservoirs using 3-II seismic data, and thisarticle is a conden& version of that lecture. There are three partsto the article: a definition of reservoir management; a discussionof the various kinds of 3-II seismic analyses that can impact thedevelopment and production of a field; and a synopsis of the pasthistory and future potential of the 3-D seismic technique,D finition. A good working definition of reservoir managementis ri-uzxim~~~nghe economic value of a reservoir by optimzi~~grtxmuy of hydmcurbms while minSzing cup~ta~kestmmts mduperdng expmxThe first thing to note is that this definition is not geophysicalor geologic; in fact, its not even an engineering definition. Reser-voir management really in the econotic prmegs of raising theworth of a property to the highest possible level. We generallymeasure economic value by such yardsticks as present worth,investors rate of return, payout, and investment efficiency. Thetask is to maximize (minimize in the case of payout) these economic

descriptors4 Economic value generally increases when more reser-ves are proved or when the reservoirs producing rate increases*Of course, capital investments (drilling seismic shooting, andlease bonuses) and operating expenses (lease rentals, staff costs,taxes, etc,) must be incurred to find, develop, and produce thesereserves, and these expenditures by themselves detract from theeconomic value. The reservoir manager thus trades off expendi-tures tiat drain present worth against the chance of increasingpresent worth by adding reserves and/or increasing production.The prwess is a continuous balancing act.

What is the role of seismic surveying, particularly 3-II, in thisbalance? Basically, it impacts reservoir management in two dif-ferent ways. First, a 34 seismic analysis can lead to identifica-tion of reserves that will not be produced optimdly, or perhapsnot produced at all, by the existing resemoir management plan.Secondly9 the analysis can save costs by minimizing dry holes adpoor producers, condemning leases that can then be dropped toavoid rental payments, etc. These concepts are summarized in myfirst major point: 3-D sehic data contribute to reservoir mm-oaks by &Zing reserves and/or lowerirq costs. Either of theseimpacts can be a sufficient justification for shooting a 3-II seismicsu~ey, Of course, the best situation is when both happen at once,and-fortunately for gmphysicists-that ' s generally the case.P owss model. One possible model of the reservoir manage-ment process is shown in Figure 2 and labeled the linear system.This model consists of the following sequence: a discovery, anevaluation of that discovery, implementation of a development planleading TVproduction of the field, and final abandonment when

Fipre l* Three-dimension4 seismic as a percentage of totalseismic in the Gulf of Mexico and North Sea. Figure 2. Resew& management-the linear system.

GEOH-IYSICS: TH E LEADIM EDGE OF EXPLORATION FEBRUARY 1989 25


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the field is no longer economic. In this scheme, a 3-D survey isshot during the evaluation phase and used to assist in the designof the development plan, after which development and productionstart up

J suggest that this linear model is not what really happens inreservoir management, except in the very simplest cases (a dis-covery followed by one or two offsets that fully develop the reser-voir). The real world generally is the process shown in Figure 3and labeled the iterative system. This model also starts with a dis-covery, but then goes into a loop where dati are constantly beingevaluated to form the basis for development/production decisions(such as locating production and injection wells, siting and design-ing platforms, setting flow rates, managing pressure maintenance,performing workovers, planning waterflood and tertiary recoverystrategies, etc.)_ When implemented, the development and produc-tion activities in turn generate new information (logs, cores, drillstem tests, pressure tests, etcm) hat change maps, revise structure,alter the reservoir stratigraphic model, and the like. Most of thetime spent in managing reservoirs really consists of going aroundthis loop Occasionally, a deeper pool or offset extension test willspin off from the evaluation, resulting in a new discovery andrevitalization of the loop. We continue with this prmess until thefield is fmally abandoned.

A 3-D seismic survey is one of the tools in the evaluation toolkit. An initial interpretation of the survey impacts the originaldevelopment plan, As subsequent events (e,g., the drilling ofdev&pment wells) occur, the added information is us& to revise

Figure 3. Reservoir management-the iterative system.

and refine the original interpretation. Often, as time passes andthe data base builds, elements of the 3-D data that were initiaIlyambiguous begin to make sense, and the interpretation becomesmore detailed and sophisticated. This is important enough to be asecond major point: the us ejidness of a 34 s&&c survey 1~~sfor th e ife of a resenoir. A 3-D survey is not something shot rightafier the discovery, interpretd once, and then put on the shelfnever to be looked at again. It hangs around for years as an ac-tive file on ones computer system!

G ometric framework. The interpretations that a geophysicistmight perform on a 3-D seismic data volume can cunveniently begrouped into those that examine the geometric framework of thehydrocarbon accumulation, those that analyze rock and fluidpropertiesq and those that try to monitor fluid flow and pressurein the reservoir (Figure 4). These analyses impact and, hopeful-ly, significantly improve decisions that must be made aboutreserves volume, well/platform locations, and recovery strategy.Thus, the anaiyses themselves are not the end products but rathermanagement tools.I am using geumetrjc framework as a collective term for spa-tial elements, such as the attitudes of beds that form the trap, thefault and fracture patterns that guide or block fluid flow, the shapesof the depositional bodies that make up a fields stratigraphy, andthe orientations of any unconformity surfaces that might cutthrough the reservoir. A 3-D seismic data volume samples thegeometric framework on a regular 3-II grid (generally 50-100 ftlaterally and HI-50 ft vertically). By mapping traveltimes to pickedevents, displaying seismic amplitude variations acres s selectedhorizons: isochroning between events, noting event terminations,slicing through the volume at arbitrary angles, compsiting her-izontaJ and vertical sections, optimizing the use of color indisplays, and employing the wide variety of other interpretivetechniques available on a computer workstation, a geophysicistcan synthesize a coherent and quite detailed 3-II picture of a fieldsgeometv.

An example of mapping geometric framework is shown inFigures 5 and 6. Figure 5 is an early structure map of the Prud-hoe Bay field on the northern edge of Alaska, The map, whichpredates any 3-D seismic shooting over the field, was used in anAAPG Distinguished Lecture in the early 70s and subsequentlypublished in 1972 by Dean Morgridge and William Smith, Jr, ofExxon (AA#G Me~&r 16). It shows the basic elements of the trapat Prudhoe Bay-the dip to the south and muthwest, tie bound-ary fault to the north, and the erosional truncation of the Sad-lerochit reservoir to the east, Figure 6, prepared by David Fisher

Figuremerit.

4* Applications of 3-D seism ic data to manage- Figure 5. Prudhoe Bay field, Alaska-1971 Sadlerwhit strut-ture map.

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Figure 6. P rudhoe Bay field, Alaska-time slice.of ARCO, s a time slice from one of the 3-D seismicvolumes hatnow exist over the field (locationshown n Figure 5). The redsand blues are seismicpeaksand troughs,and the time slice cutsthe volume at about he level of the unconformity runcating heSadlerochit.One can clearly see he Sadlerochit ubcrop nd thenorthernboundary ault on the time slice. More subtle elementsof the geometric rameworkare a lso evident, suchas additionaleast-west nd northwest-southeastaulting. This exam ple illus-tratesa third major point: 3-D seismicdata map the gross. con-trolling elementsof a field. This type of analysis s the traditionaluse of the 3-D seismic echniqueand ha s contributedvery sig-nificantly to th e geologiccharacterixation f many hydrocarbontraps.

An exampleof ima ging stratigraphic hap eswith 3-D seismicdata is shown n Figures 7 and 8. The d ata volume comes romthe Matagordaarea of the offshoreGulf of Mexico, and the ex-ample is about to be publishedby W.C. (Rusty) Riese and BenWinkehnan of ARCO n the AAFG Atlas of SeismicStmtigraphy(Vol. 3). A single seismicsection Figure 7) in the 3-D volumecontains variety of nearly flat events.Someappear nd thendis-appear; othersvary laterally in am plitude; and the stratigraphicsignificance f any particularreflector s not obviouson the 2-Ddisplay.Take noteof the shortblack event (at about0.7 s) locatedlaterally and directly above he zero tick on the scalebar. A timeslice through he 3-D volume (Figure 8) reveals hat the event isa transverse ut througha meanderingstreamchannel, and the

stratigraphic ituation eco mes learwhen he full spatialsamplingof the 3-D vo lume s utilized. (The greenbands rossing henorth-em part of the slice are fault cuts coming up through he data.)The major point here is the following: minor characterchangesin 3-D seismic ata tend o correlatewith red geologicchanges.The variationsgenerally are not noise or acquisition/processingerrors, and the challenge s to correctlydeduce heir geologicsig-nificance.Rock and fluid properties. The secondgeneral grouping of3-D seismic nalyses Figure 4) encompasseshose argeted t thequalitativeandquantitative efinitionof rock and fluid properties.Amplitudes,phasechange s, nterval traveltimesbetweenevents,frequency ariations,and othercharacteristicsf the seismicdataare correlatedwith porosity, luid,type, lithology, net pay thick-ness, nd other reservoirproperties.The c orrelations sually re-quire boreholecontrol (we11 ogs, cuttings, cores, etc.) both tosuggestnitial hypothesesnd to refine, revise, and test proposedrelationships. n interpreterdevelops hypothesis y comparinga seismicparametern the 3-D volume at the ocationof a well tothe w ells information, often through he intermediaryof a syn-thetic seismogrammatch. The hypothesiss then used o predictrock/fluid properties way from the boreholecontrol, and sub-sequentdrilling v alidates or invalidates) he concept. For e x-ample, 3-D seismic urveys re commonlyused n the productivePleistocenerendsof the offshoreGulf of Mexico to directly map


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GEOEHY%C%THE LEADING EDGEOFEXPLORATION FEBRUARY 1989

gas saturation. One correlates seismic amplitude anomaiies withgas-saturated sandstones and then maps the areal ex&nt (and some-times net feet of pay) of these bright spots laterally and verticallythrough the dati volume.

A less common type of analysis ti Uustrated in Figure 9, whichwas prepared by Stanley Stanulonis and Naresh Kumar of ARCOand presented at the 1988 Annual Meting of the AAPG. This ex-ample is located on Alaskas North slope, and the formation ofinterest is the Lisburne, a carbonate tiat produces from below theSadlerochit at P&hoe Bay* The amplitudes of the Lisbume reflec-tion were determined at points of well contro1 and compared toLisburne porosity-thichesses measured in the same welIs* Thecomparison prtiuced a methodology that was used to transformseismic amplitudes directiy into porosity-thickness values at gtidpoints between wells. Figure 9 is the seismic horizon now scaledto porosity-thickness. several wells drilld after this analysis havetested the quality of the porosity-thickness predictions, and thetests have matched the pre&ctions to within a few units.

The major point here is this: 3-D S&WCC&ti guide intenve~~inteqxdations of mstmoir propertk~ Given a 3-D survey, onedoes not have to settle for crude, linear inteplations of reservoirparameters between wells. The reservoir manager can use the seiswrni~ volume to pinpoint and understand nonlinear lateral changes-an approach that nearly always results in lower costs, fewersurprises during development, and htter production.

F ow swveillarrce. The third, and last, general grouping of 3-Dseismic analyses (Figure 4) consists of those designti to look atthe actual flow of the fluids in a reservoir, such flow surveillanceis possible if the following is done:

l Acquire a baseline 3-D data volume at a point in calendartime_

l Allow fluid flow to occur through production and/or injec-

tion with attendant pressure/temperature changes.l Acquire a second 3-D data volume a few weeks or months

after the baseline,l Observe differences between the seismic character of the two

volumes at the reservoir horizonl Demonstrate that the differences are the result of fluid flow

and pressure/temperature changes.Of course, one must be careful not to vary seismic acquisition

and processing parameters drastically between surveys and there-by introduce differences that can be mistaken for fluid flow ef-fects, One exp&s that the seismic character of horizons above thereservoir would be virtually identical between the volumes (geol-ogy generally changing over a much longer time than fluid flow!)Hence, an interpreted flow-induced difference can be indirectlyvalidated by verifying that the difference occurs at the reservoirevent, but not elsewhere in the 3-D volume. Moreover, one canacquire a third, a fourth, etc+ survey and continue the surveil-lance by computing additional 3-II difference volumes.

Flow surveillance with multiple 3-II seismic surveys is at avery early stage of research and development, but its potential im-pact on re=rvoir management is enormous* Most current practiceof the techtique has been directed toward monitoring enhanced oilrecovery (EOR) prt~cesses. An example is shown in Figure 10from a paper published by ARC&S Roben Greaves and TerranceFulp (GEUPHYSICS 1987)_An experimental, oxygen-driven ther-mal EOR pilot was performed on a depleted oil field called theHalt sand Unit located in north Texas* The top section in Figure10 is a line through a 3-D data volume acquird prior to the startof the pilot. The Holt sand is the event identifiti by the white tri-angles, and its seismic amplitude is low. In this color~coded dis-play of envelope amplitude, the bright event is a limestone lyingseveral hundred feet below the Holt and not associated with thereservoir. The middle section in Figure 10 lies in the sme spatialposition in the 3mD dati volume as the top section, but was ac-

Figure 7. Matagorda l3Iock 668, offshore Texas-seismic section.


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Figure 10. Holt Sand Unit EOR pilot-seismic sections.

30 GEOPHYSICS: THE LEADING EDGE OF EXPLORATION FEBRUARY 1989


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quired a few months after the start of oxygen injection/thermalcombustion.Likewise, the bottom section s the same line reshotabout a ye ar a fter start-up. One can ob serve that the oxygen in-jection/thermal combustionprocess has produced a dramatic in-crease n the strengthof the Holt sand reflection and that moreand more of the formation s affected as calendar ime passes.Th ecombinationof ox ygen njection and creation of com bustiongasesincreasesgas saturation n the reservoir (in effect, the experimentis crea ting an a rtificial bright spot), the thermal process s alter-ing the state of the reservoir, and the m ultiple seismic data setsare m onitoring the changes.The lesson here is that 3-D seismicsnapshots an map chan-ges in jluid/pressure/flow regimes. Although not yet as commer-cialized as mappinggeometric rameworksor estimating ock/fluidproperties between wells, this applicationof 3-D seismic survey-ing ma y eventua lly become ust as imp ortant as the other two. Ithas the potential to directly me asure reservoir performance ,provide timely feedb ack h at can change development/productionplans, and be far m ore spatially specific than pressure ests. n thefuture, the techniquemight be used o monitor gascap movements,control productionand njection rates o r op timum recovery, mappressure/tem perature istributions, and even decipher stresspat-terns, particu larly in tectonically active areas .R oats.he first 3-D seismic survey ever shot appears o havebeen an experimental survey acquired by Exxon Production Re-search Company in 1967 at Friendswood field near Houston,Texas . A description of the survey and some of the data werepublished by George Walton (GEOPHYSICS 1972). Various pet-roleum companiescarried out other experimen tal surveys during1967-72, including some performed with transducers n watertanks by W illiam French and coworkers at Gulf Oil Corporationabout 1970. It was not until 1973, however, that the first com-mercial 3-D seismicprogram was conducted-a land survey shotin Lea County, New M exico, by GeophysicalService Inc., for aconsortium consistingof Amoco, ARCO, Chevron, Mobil, Phil-lips, and Texaco. The first commercial marine survey followedtwo years later in 197%one acquired n the High Island area ofthe Gulf of Mexico by GSI for Su n Oil Company. Usage of thetechnologygrew steadily from the mid-70s onward, particularlyin the marine environmen t, as acquisition and processing im-proved. Th e best available evidence is that more th an a hu ndred3-D seismicsurveyswere shotworldwide by 1980. Steady nnova-tions in acquisitionand processing echniques stream er tracking,real-time binning, 3-D migration, 3-D velocity analysis,etc.), theadvent of supercom puters, nd the explosive growth in com putergraphicsworkstations or interpretationhave continued o fue l theusageof 3-D seismology. t is virtually certain that more than athousand3-D surveyshave now been acquiredworldwide by thepetroleum industry.F uture. A very safe prediction is that steady growth in the ap-plication and sophistication f 3-D seismic technology s going tocontinue n the foreseeable uture. The following are some specificareas n which progress s occurring.Acquisition/processing/interpretationethods.At sea, oper-ators are shootingsurveys with various combinationsof multiplestreamers, multiple source arrays, and multiple boats; are ex-perimenting with towing streamers n circles around targets ikesalt domes to improve the imag ing of radial faults; and are shoot-ing into receivers fixed on the oceanbottom. On land, where oneis free from the constraintsof towing a streamer, operators aredeploying many inno vative acquisitiongeometries hat make fulluse of the mu ltichannel capabilities of modem seismic systems.The geometries accoun t for terrain and c ultural obstacleswhileoptimizing subsurface overageand mixes of o ffsetsand azimuths,all at the lowest possiblecost. Some experimentalwork is under-way to acqu ire 3-D, three-componentsurveys, thus adding shear

and converted wave volumes o the standardcompressionalwavevolume. Advances in supercomputingwill continue to sp eed upprocessingand permit the inclusion of more sop histicated lgo-rithms in processing schemes. Infusion of analytical techniquesfrom remote sensing and other imag e processingdisciplines isbeginning to affect 3-D seismic interpretation. Autom ated infor-mation extraction (for example, algorithm s hat pick events aftera few control points are specified) is becom ing a routine part ofinterpretation, and m any facets of 3-D seismic analysis areamen able o being impacted eventually by artificial intelligencetechnology.Routineuse n exploration.A recent nnovation n 3-D seismicsurveyinghas been acquisitionalong ines spacedwidely apart ol-lowed by filling in of the data volume by num erical nterpolationprior to performing 3-D migration. This 3-D scheme (knownvariously as reconnaissance, xploration, or wide-line 3-D) de-pendson a good nterpolationalgorithm o be successful nd, eventhen, some steep-dip nform ation is lost. Howeve r, the techn iquehas the poten tial to lower acquisitioncosts to a point where it isfeasible to shoot 3-D for exploration, and these types of surveysare now p enetrating he seismic marke t.Three-dime nsional eismic with d ownho le sources/receivers.The standard3-D seismic data volume is acquired with sourcesand receivers at the earths surface. It is logistically possible toput sources n d/or receivers n boreholesand to record part or allof the 3-D data volume with this downhole hardware. This ap-proach s an active area of research. Depend ing upon the acquisi-tion configuration, one records various kinds and am ounts ofreflectedand transmitted eismicenergy, which c an then be so rtedout to provide information on geometric framework, rock/fluidproperties, and flow surveillance ust like surface surveys. Ad-vantagesof downhole placementare tha t higher seismic frequen-cies generally can be recorded thereby improving resolution)an dthat surface-associatedeismic noise and staticsproblems are les-sened or avoided. The m ain disadvan tages re that ones sourceand receiver plants are constrainedby the p hysical locations ofavailable boreholes;borehole seismologycan be affected by tubewaves and the like, so is not noise-free; a boreh olesourcecannotbe so strongas to damage he well; a nd he logisticsan deconomiesof operating n boreholesare com plex, though not necessarily l-ways worse, compared o opera ting on the surface. One ca n im-agine a time when borehole seismic sourcesand receivers mightbe standardcomponentsof the hardware un into wells and ac-cepted as routine and valuable devices for reservoir characteriza-tion and flow su rveillance.S mm ary. The petroleum industrys 20-year experience with3-D seismic surveying is an example of a technological andeconomicsuccess.Today, the investment n a 3-D survey ypical-ly results n fewer developmentdry ho les, improved placementofdrilling locations o max imize recovery, recognitionof new drill-ing o pportunities, and mo re a ccurate estimates of hydrocarbo nvolumeand recovery rate. These outcomes mprove he economicsof dev elopment/produ ction lans and make the surveyscost-effec-tive. More s killful reservoir manag emen twill be a theme of the199Os,and 3-D seismic technology will be part of the adva nce-ment. C

Acknowledgments: thank the many ndividualswithin ARCO ndin other organizations n the geoscience om munitywhose deas,datu, and suggestions ontributed o the content nd graphicsofthe Fall 1988 SEC Distinguished ecture; the local SEG sectionsand universitiesor their invitations o speak o them: he SEG orits logistical and inancial s upportof the Lecture; and A RCOOiland Gas Com panyfor t ongoing upport fparticipation n profes-sional societyactivities.

GEOPHYSICS: THE LEADING EDG E OF EXPLORATION FEBRUARY 1989 31

25-Reservoir Management Using 3-d Seismic Data

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