2 Oilfield Review

The Time for Depth Imaging

Uwe AlbertinJerry KapoorRichard RandallMart SmithHouston, Texas, USA

Gillian BrownChris SouflerisPhil WhitfieldGatwick, England

Fiona DeweyWintershall Noordzee BVThe Hague, The Netherlands

Jim FarnsworthBPHouston, Texas

Gary GrubitzBHP BillitonHouston, Texas

Mark KemmeClyde Petroleum Exploratie BVThe Hague, The Netherlands

For help in preparation of this article, thanks to Ian Anstey,Robert Bloor, George Jamieson, Patrick Ng and Erick Zubay,Houston, Texas, USA; and Mark Egan, Gatwick, England.

Many of todays exploration targets cannot be seen with conventional seismic-

imaging methods. Operators now are getting a clearer pictureeven of the most

complex featuresusing prestack depth imaging. The more accurate results

reduce exploration risk and help delineate reserves.

Throughout the last century, interpretersaccepted seismic images processed and dis-played in the time domain. In many of todaysactive exploration areas, especially where struc-tures are complex and seismic velocities varyabruptly because of faulting or salt intrusion,time-domain processing can give misleadingresults; only depth imaging can define the trueposition and correct geometry of subsurface fea-tures. In some cases, the difference betweendepth and time images can make or break aprospect: structures gain or lose closure, targetsmove by hundreds of feet or meters, and reservescan be added or lost. The difference can be anexpensive dry hole instead of a discovery.

This article explains how depth imaging hasemerged as the technique of choice for process-ing seismic data to image complex subsurfacefeatures. Case studies show how oil and gascompanies operating in the Gulf of Mexico, NorthSea and onshore US are improving their drillingsuccess rates with depth imaging.

Events in Seismic HistoryOver the course of the 20th Century, notable mile-stones marked advances in seismic prospectingmethods. Although many new technologies havetaken about 10 years to mature from first intro-duction to accepted practice, each one has ulti-mately created new exploration opportunities.

Starting in the 1920s, single-fold analogtraces were introduced to detect dipping subsur-face layers (next page).1 In the 1930s, this innova-tive technique was the key to discoveries aroundsalt domes, and became standard practice. The1950s saw the arrival of multiple-fold seismicdata achieved by common depth-point (CDP)

stacking, which markedly improved signal-to-noise ratio. In the 1960s, digital data acquisitionand processing were introduced, replacing earlieranalog and optical methods. This created majorimprovements in the quality of seismic data andled to many new discoveries worldwide.

Throughout the 1970s, digital data and two-dimensional (2D) surveys became common.Together, these technologies opened up theNorth Sea and other challenging areas. Time-based processing was standard, but 2D poststackdepth migration was introduced and tested. Thefirst small three-dimensional (3D) surveys were acquired over developed fields to improvereservoir delineation. In the 1980s, 3D surveysgained wide acceptance in the industry andtransformed the exploration business. Traceattributes and bright spots were used as seismicindicators of hydrocarbons.

By the 1990s, seismic contractors routinelyacquired 3D exploration data over vast portions ofthe worlds continental shelves. Three-dimen-sional poststack time migration evolved tobecome standard practice, reducing finding coststo their current levels; and 3D prestack depthmigration was introduced for particular cases.Today, many operators wont drill without 3D dataover their prospects, and in the areas of highestrisk, wont drill without prestack depth imaging.

Currently, depth imaging is creating explo-ration opportunities in regions that were consid-ered too risky just a few years ago. Thistechnique is helping explorationists generatenew subsalt prospects in the deepwater Gulf ofMexico and discover new reserves in the NorthSea that were unimaginable using conventionaltime-processed data.

1. Fold is the number of source-receiver pairs whose sig-nals constitute a trace.

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> Chronology of selected advances in seismic methods.

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Introduction to ImagingImaging is the process that brings seismic reflec-tions into focus at their proper positions. It con-sists of two main elementsstacking andmigration. Stacking increases signal-to-noiseratio by summing records obtained from severalseismic shots reflecting at the same point. Thesimplest case to illustrate is a flat layer of uniformvelocity overlying the reflector. Traces from sev-eral source-receiver pairs, centered on the reflec-tion point but separated by different distances, oroffsets, are gathered together (below). The varia-tion in arrival time with offset is called moveout.The shape of the arrival times plotted against off-set defines a hyperbola. Before the gather can bestacked, the traces must be shifted to alignarrivals. The offset-versus-time parameter thatdescribes the shifts defines the stacking velocityof that layer. The result of stacking is a singletracethe enhanced version of a signal thatwould have been recorded for a normal-incidence, or zero-offset, shot at the midpoint ofthe source-receiver pairs.

The second ingredient in imagingmigra-tionuses a velocity model to redistributereflected seismic energy from its assumed posi-tion at the midpoint to its true position (next page,top left). One of the several classes of migrationmay be chosen depending on the complexities ofthe target and overburden structures. Simple

structures and smoothly varying velocities can beimaged with simple migration routines that mayfail to work on complex structures with rapidlyvarying velocities.2

Migration is accomplished by various solu-tions to the wave equation that describe the prop-agation of elastic waves through rock. Migrationalgorithms often take the name of their inventor,such as Kirchhoff, or the type of mathematicalsolution, such as finite-difference.3 Each type ofmigration has advantages and drawbacks.

Migration can be performed in twodomainstime or depthand either before orafter stacking. Certain imaging problems can besolved with time migration, but the most complexproblems need depth migration. In time migra-tion, the velocity model, also called the velocityfield, may vary smoothly (next page, top right).The velocity model has two-way traveltime as itsvertical axis. Seismic velocity increases withtraveltime, and horizontal variations are gradual.Since these constraints are valid in most sedi-mentary basins, time migration is often applica-ble, and is used in most parts of the world.

In depth migration, the velocity model mayhave strong contrasts horizontally or vertically.Depth migration is chosen when steeply dippingfaults, folds or intrusions juxtapose layers withvastly different elastic properties. Depth migra-tion needs an accurate velocity model in depthand is a more labor-intensive operation.

Migration applied after stackingpost-stackis much faster than migration beforestacking, because stacking reduces by an orderof magnitude the number of traces that must beprocessed. For poststack migration to be suc-cessful, the assumptions made in stacking mustbe well-founded: the amplitude of the stackedtrace must represent that of the normal-inci-dence trace and reflected arrivals must beapproximately hyperbolic. These suppositions arevalid only when variations in lithology and fluidcontent over the span of the gathered traces canbe ignored and when the structure is simple. Anyother conditions call for prestack migration.

Performed before stacking, prestack migra-tion can handle the most complex structures andvelocity fields. In the past, the main constraintson prestack migration were the computing powerneeded and the time and skill required to con-struct the velocity model within a reasonableturnaround time. Advances in computing technol-ogy have eased these constraints.

Creation of the velocity model still remains atime-consuming process and depends on thelocal geology. In areas where the geology is lay-ered, or well-defined fault blocks exist, velocity-model building for depth migration proceeds on a

4 Oilfield Review

Withstackingvelocity

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> Stacking traces from a common depth-point (CDP) gather. Traces from several source-receiver pairs at different offsets from the common depth point arecollected to form a CDP gather (left). Gathered traces are displayed in coordinates of time versus offset (center), in which the shape of reflection arrivalsfrom a flat reflector defines a hyperbola. The arrivals are shifted into alignment using a stacking velocity, or offset-versus-time relationship, and stacked(right), or summed, to create a single trace with higher signal-to-noise ratio than that of any of the original traces.

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layer-by-layer basis. An initial model is con-structed from the most suitable data available,then updated through several iterations ofprestack depth migration for each layer. The ini-tial velocity model can be constructed using allthe available information, such as stacking veloc-ities, time-interpreted horizons and velocitiesfrom borehole data. Stacking and borehole veloc-ities can show representative velocity trends,which should be taken into account in the model.

When the structure is not too complex, theentire velocity model can be updated and con-structed layer by layer rather quickly. In morecomplex cases, the velocity analyst definesblocks or other volumes bounded by faults orintrusions, then builds the model for each blocklayer by layer.

In areas where geology is more continuous,such as in the Gulf of Mexico, a continuous sed-iment-velocity model is defined using eithertomography or local velocity updating. Once thesediment velocity is defined, salt bodies areinserted after their positions are determinedusing several iterations of depth migration.

In areas where anisotropy is an important fac-tor, significant differences may appear betweenborehole-based velocities, which typically repre-sent velocities in the vertical direction, andstacking velocities, which represent horizontalvelocities. These differences must be accountedfor by introducing anisotropy into the velocitymodel. More discussion on depth migration in anisotropic velocity fields appears later in this article.

Collaboration between operator and servicecompany can facilitate successful velocity modelbuilding. Operating company interpreters oftenhave better knowledge and expectations of thesubsurface, and can help interpret layer bound-aries and salt features for the velocity model.Service company staff, with their knowledge ofprocessing, incorporate these interpretations tohelp create the model for depth migration.

Depth Imaging in the Gulf of MexicoThe Gulf of Mexico has been the most publicizedproving-ground for prestack depth-migrationtechniques.4 Salt bodies in various stages ofintrusion and uplift have created complex struc-tures that both motivate and challenge explo-rationists. Salt geometries can vary enormously,and are critical in terms of hydrocarbon migration

and trapping. Salt massifs can appear to berooted to a deeper salt layer or completelydetached and floating. The high contrast in seis-mic velocity between the salt at 14,500 to15,200 ft/sec [about 4500 m/s] and sediments,often at less than half that value, causes prob-lems for time-migration approaches.

2. For more on prestack, poststack, time and depth migra-tion: Farmer P, Gray S, Whitmore D, Hodgkiss G, Pieprzak A,Ratcliff D and Whitcombe D: Structural Imaging: Towarda Sharper Subsurface View, Oilfield Review 5, no. 1(January 1993): 2841.

3. Kirchhoff migration is based on Kirchhoffs solution to thewave equation.

4. Huang S, Ghose S, Sengupta M and Moldoveanu N:Improvements in 3-D AVO Analysis and StructuralImaging of Dipping Salt-Flank Events Using Amplitude-Preserving Prestack Depth Migration, The Leading Edge20, no. 12 (December 2001): 1328, 1330, 1332, 1334.Donihoo K, Bernitsas N, Dai N, Martin G and Shope D:Is Depth Imaging a Commodity? The Impact of NewImaging Technologies and Web-Based Collaboration,The Leading Edge 20, no. 5 (May 2001): 486, 488, 490, 492,494, 496, 543.Albertin U, Woodward M, Kapoor J, Chang W, Charles S,Nichols D, Kitchenside P and Mao W: Depth ImagingExamples and Methodology in the Gulf of Mexico, TheLeading Edge 20, no. 5 (May 2001): 498, 500, 502, 504, 506,508, 510, 512513.

Migratedtrace

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> Migration of reflected seismic energy. For thissimplified two-dimensional (2D) example, migra-tion repositions the data trace from its recordedposition at the source-receiver midpoint to itstrue position (MIG) using a velocity model. In 3Dcases, reflections may be redistributed to andfrom positions outside the plane containing thesources and receivers.

Simple velocities + simple structure = poststacktime migration

Complex velocities + simple structure = poststackdepth migration

Simple velocities + complex structure = prestacktime migration

Complex velocities + complex structure = prestackdepth migration

Incr

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> Simple and complex velocity models and structures treated by four migration classestime, depth,prestack and poststack. Poststack models are on the left and prestack models are on the right. Modelsappropriate for time-based migration are on the top, and depth-based models are on the bottom. Fortime migration, the velocity model may have smooth variations, but only with depth, and only monoton-icallyalways increasing with depth, never decreasing. Depth migration is required for more complexvelocity models, such as those with lateral variation or decreases of velocity with depth. Poststackmigration works with models of low structural complexity. Prestack migration can handle even themost complex models.

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Technological advances have broughtincreases in production ever since hydrocarbonswere discovered in the Gulf of Mexico (below).Early on, drilling technologies were key to exploration success. More recently, seismic-imaging techniques have helped sustain the discovery rate.

In the late 1980s, operators started testing 2Dprestack depth migration as a way to improveimages of layers truncating against the flanks ofsalt domes. In 1993, partners Phillips Petroleum,Anadarko and Amoco were the first to announcea subsalt discovery in the Gulf of Mexico with the

Mahogany prospect. They attributed this successto prestack depth imaging.5

Today, companies continue to explore belowsalt, and many are also looking in deeper water.Several of the recent large discoveries in the Gulfof Mexico are in deep waterdeeper than5000 ft [1500 m] (bottom left). In these areas, thecost of drilling a well can exceed $50 million, butthe rewards can be great. The Crazy Horse dis-covery by BP contains estimated reserves of 1 bil-lion barrels of oil equivalent (BOE). BHP Billitonhas reported 200 to 450 million BOE recoverablereserves at Mad Dog and 400 to 800 million BOEat Atlantis.

Reducing risk is a key concern for deepwateroperators, and prestack depth imaging is one ofthe technologies that help reduce risk. Depthimaging was performed to reduce drilling riskover many Gulf of Mexico discoveries such asCrazy Horse, Llano, Mad Dog, Atlantis and oth-ers. For BHP Billiton, prestack depth imaging isthe critical technology for reducing risk andappraisal at Atlantis, Mad Dog and the rest ofthe Western Atwater Fold Belt trend that encom-passes these discoveries. BP credits prestackdepth-imaging breakthroughs with helping todescribe the elements of the Crazy Horseprospect and to position the discovery well.6

Imaging a seismic volume containing a saltbody is different from traditional processing, inwhich data tapes are sent off for processing anda finished product is returned to the interpreterfor examination. Subsalt imaging requires sev-eral iterations of migration and interpretation(below). Many of these steps are based on proprietary processing techniques, allowing contractors to differentiate their results fromthose of other contractors.

The first step after general prestack process-ing is to build the initial velocity model for thelayers overlying the salt. In the Gulf of Mexico,sediments typically are sand-shale sequenceswithout strong velocity contrasts between layers.The initial velocity model can often be derivedfrom stacking velocities to produce a smoothinterval-velocity field describing the sediments.

6 Oilfield Review

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> Impact of technological breakthroughs on Gulf of Mexico success rates.Starting with the early achievements in drilling capability, and continuingthrough modern seismic methods, each advancement has yielded an identifi-able increase in production.

> Recent deepwater Gulf of Mexico discoveries, with many occurring near salt bodies. Large recentdiscoveries have estimated reserves in the hundreds of millions of barrels. Several of these have beendiscovered with the help of prestack depth imaging.

Updatevelocitymodel

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> Data-processing flow for subsalt prestackdepth migration. The process is a complex inter-play of several steps. Building the velocity modelitself requires iterations in prestack depth migra-tion to define the velocity of each layer and thegeometric boundaries of each layer.

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The second step takes this velocity model andupdates it. Velocity analysts have several waysof revising models, most belonging to a categoryof methods called tomographic inversion.Tomography uses traveltime information derivedfrom seismic data to refine velocity models.Classical reflection tomography uses the differ-ence between predicted and observed reflectiontraveltimes.7 Ray tracing predicts the arrivaltimes of reflections on common depth-point gathers at control points. On each gather, theshape of the actual arrival time of the shallowestreflector is compared with the predicted arrivaltimes, and the velocity that best flattens theactual arrival times is used to update the model.This step is time-consuming and requires expertsin both processing and interpretation to create amodel that satisfies the data at all control points.

The next step applies depth migration usingthe updated velocity model. The migrated tracesare gathered again and arrival flatness checked. Ifthe preliminary time migration shows the top of

salt to be smooth, or structurally simple, the veloc-ities of the overburden can be used in a poststackdepth migration to obtain an image of the top ofsalt. If the top of salt is rough, or structurally com-plex, prestack depth migration should be applied.

After the top of salt is imaged and inter-preted, the velocity model is updated by fillingthe volume below the salt top with a uniform saltvelocity. With this new velocity model, the volume is again prestack depth migrated, and thebottom of salt comes into focus.

Applying the correct migration technique canbring surprising changes to the seismic image.Interpretation of one time-migrated section fromthe Green Canyon area of the Gulf of Mexicoshows two anticlinal structures created by salt

intrusion (above). The salt body on the left has adomed top and a flat base, and creates a shadowbeneath, obscuring deeper reflections. The saltintrusion on the right appears to have piercedthrough the top of the anticline and left a domeof salt behind.

With prestack depth imaging, the picturechanges completely. The salt body on the left isstill domed, but is thicker, with a sloping base.Layers can now be seen below the salt. The saltfeature on the right looks entirely different.Instead of two disconnected salt bodies, the newimage shows a single hourglass-shaped bodywith clearly delineated sides and base. Insteadof rising in an anticlinal structure, sediments aretruncated along the flanks of the salt hourglass.

5. Westcott ME, Leach MC, Wyatt KD, Valasek PA andBranham KL: Mahogany: Seismic Technology Leading tothe First Economic Subsalt Field, Expanded Abstracts,65th SEG International Meeting and Exposition, Houston,Texas, USA (October 8-13, 1995): 11611164.For more on subsalt exploration: Farmer P, Miller D,Pieprzak A, Rutledge J and Woods R: Exploring theSubsalt, Oilfield Review 8, no. 1 (Spring 1996): 5064.

6. Pfau GE, Chen RL, Ray AK and Kapoor SJ: SeeingThrough the Fog: Improving the Seismic Image at Crazy

Poststack Time Imaging Prestack Depth Imaging

> Comparison of time migration and depth migration in the Green Canyon area of the Gulf of Mexico. The time migration (left) shows twosalt bodies, each uplifting and doming the overlying sediments. The salt body on the left has a domed top and a flat base, and creates a shadow beneath. The one on the right seems to be in two pieces: a floating salt pillow has detached from the dome below.Prestack depth imaging (right) retains the general shape of the body on the left, although its base is now sloping. However, the depth imag-ing reveals layers beneath, which were shadowed in the time migration. The salt intrusion on the right has a completely different shapewhen depth migrated. Instead of rising in an anticlinal structure, sediments are truncated along the flanks of an hourglass-shaped salt body.

Horse, presented at the AAPG Annual Meeting, March1013, 2002, Houston, Texas, USA.Yielding CA, Yilmaz BY, Rainey DI, Pfau GE, Boyce RL,Wendt WA, Judson MH, Peacock SG, Duppenbecker SD,Ray AK and Hollingsworth R: The History of a New Play:Crazy Horse Discovery, Deepwater Gulf of Mexico, pre-sented at the AAPG Annual Meeting, March 1013, 2002,Houston, Texas, USA.

7. Other types of tomography can use refracted or trans-mitted waves.

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In another portion of the Green Canyon area,the tops of three large salt pillows are fairlyclearly imaged by poststack time migration, butthe bases are not (left). One reasonable interpre-tation would place the bases of the salt at thelower limit of the reflectionless area of the seis-mic image. There is some indication of layeringbetween the salt bodies at great depth.

Prestack depth migration reveals a surpris-ingly different image. The two large salt bodieson the left now are connected to roots thatplunge to about 40,000 ft [12,200 m]. The root ofthe middle salt feature is about 3 miles [5 km]across. The vast volume between the two saltroots is filled with dipping sediments that aretruncated against the roots.

One of the achievements of the WesternGecoapproach to prestack depth migration is the abil-ity to image dips beyond 90 degrees, that is,layers that are overturned or below salt over-hangs. Migration methods trace rays through thevelocity model to a reflector, then follow the raysback to the surface. The rays bend at each inter-face according to the angle of incidence and thevelocity contrast between layers.

Usually it is sufficient to consider only thoserays that bounce from the top side of a reflector.However, in some cases, reflections of interestcan also occur from the bottom sideas in thecase of reflections from underneath salt over-hangs. Properly accounting for these reflectionsin migration requires the ray tracing to be doneover long distances. By taking advantage ofthese rays, called turning rays, the undersides ofsalt overhangs can be imaged clearly.

In another example from the Gulf of Mexico,poststack time migration is able to image thenorthern flank of a salt intrusion, but the southernside is lost in a shadow (next page, bottom). Thetime migration did not use turning rays. Prestackdepth imaging, incorporating turning-ray energyas well as energy passing through the salt, illu-minated the steeply dipping layers and the over-hanging salt on the south flank of the intrusion.

Imaging in the North SeaThe Gulf of Mexico is not the only place whereoperators are using depth imaging. Many parts ofthe North Sea can claim structural complexityrivaling that of Gulf of Mexico salt intrusions. Inaddition to tectonically active salt, North Seabasins exhibit expanses of chalk and large-scale faulting above and below the salt. Thesmoothly varying sand-shale sequences over-lying the Gulf of Mexico salt bodies may seemsimple by comparison.

8 Oilfield Review

Poststack Time Imaging

Prestack Depth Imaging

> Time and depth migrations of three large saltfeatures. Poststack time migration (top) revealsthe tops of the salt intrusions. However, thismethod leaves an unclear image of the salt bases;they might be interpreted at the lower limit of thezone that has little reflection or no character.Interpretation of the prestack depth image (bottom)suggests that the two left-most salt bodies arenot floating, but connected to roots that extend to40,000 ft [12,200 m].

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Wintershall Noordzee BV began exploring inBlocks K10 and K13 in the Broad Fourteens basin of the Dutch sector of the North Sea in1968 (right). Since then, more than 30 wells havebeen drilled, delineating seven producing fields.As these fields enter their final years of produc-tion, new technology is being deployed to iden-tify additional reserves and extend the producinglife of this mature area.8

The area is structurally complex, with large-scale normal faulting, overthrusts and salt intru-sions. Large velocity contrasts around the saltdomes and across major faults cause traditionalseismic-imaging methods to produce poor pic-tures of structures and faults. Deep channels cutinto the Tertiary sequence that overlies a thickchalk unit of variable thickness and velocity. Themain reservoirs are even deeperthe MainBuntsandstein and Rotliegend sandstones. High-amplitude carbonate rafts can be mistakenlyinterpreted as Top Rotliegend reflectors, result-ing in false targets.

8. Dewey F, Whitfield P and King M: Technology OffersNew Insight in a Mature AreaA 3D PreSDM CaseStudy from the Dutch N Sea, Transactions of the EAGE63rd Conference and Technical Exhibition, Amsterdam,The Netherlands, June 1115, 2001, paper A-04.

Constant velocity

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3D Poststack Time Imaging 3D Prestack Depth Imaging

> Imaging under a Gulf of Mexico salt overhang with time and depth migration.Poststack time migration (left) manages to image the north side of a salt diapir, butthe southern side is lost in a shadow created by an overhang. By including turningrays (inset) and rays that pass through the salt, prestack depth migration (right)images the steeply dipping layers and the overhang on the south side of the intrusion.

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< The K10 and K13 blocks in theBroad Fourteens basin, southernNorth Sea. Wintershall NoordzeeBV has achieved a clearer seis-mic picture of their reservoirs inthis gas-producing region byapplying prestack depth imaging.

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An early depth-migration project in 1996 overa 50-km2 [19.3-sq. mile] portion of the two blocksshowed some imaging improvements, but usedsimplistic velocity-modeling techniques, and sothe results lacked the detail to improve fine-scalestructural imaging.

Enhanced imaging and increased resolutionwere required to improve understanding of thegeological history of the area and identifyremaining traps. In 1999, Wintershall andWesternGeco carried out a high-fidelity 3Dprestack depth migration of both blocks. The newproject incorporated data from three 3D surveyscovering an area of 880 km2 [340 sq. miles].

The success of every depth-migration projectdepends on the accuracy of the velocity model.To create an accurate model, a meticulousapproach was developed using a combination of state-of-the-art tools and more conven-tional techniques.

Iterative layer-stripping formed the backboneof the analysis. For each layer, a combination oftomography and multivelocity depth scans was

used to derive the model. To verify the velocitiesof each layer, a dense grid of 3D prestack depthmigrations was generated. The depth stackswere used to update the structural model, andthe gathers were examined to monitor andupdate the velocities. This allowed both thestructural and velocity variations to be continu-ously and consistently tracked and checked foreach of the 11 layers in the model as it was built.

The new images showed significant improve-ments over the previous time- and depth-migrated data sets, especially in the tectonicallycomplex areas. For example, results from the1996 project using a simple velocity model gavean unclear image of the top of the Rotliegendsandstone reservoir under a complex fault (below). The new depth migration with thedetailed velocity model gave a much clearerimage of this potential reservoir interval.

In a second example, a feature that is difficultto interpret in the time-migrated section becomesidentifiable as a pop-up of the Rotliegend formation in the properly depth-migrated image

(next page, top). What appears to be an isolateddiscontinuous reflection in time migration can beseen in the depth-migrated section to be anabrupt pop-up with near-vertical sides. The com-plex structure overlying the pop-up, combinedwith its steeply dipping flanks, makes this prob-lem difficult to solve with time migration, butcompletely tractable with depth migration.

The projects success relied on close coopera-tion between processing geophysicists, inter-preters and researchers from both Wintershalland WesternGeco, along with the optimization ofall available technologies. The additional effortput into deriving the detailed velocity model has shown the benefits of aiming for the 90%correct solution rather than making do with a70% result, while satisfying tight operationaltime and cost constraints.

A complete reinterpretation of the area isunder way and will be combined with a basin-modeling study to improve definition of the pro-ducing fields and identify the presence of anyuntested reservoir compartments.

10 Oilfield Review

Depth Imaging 1996 Depth Imaging 1999

Rotliegend sandstone

> Comparison of depth migrations with simple and complex velocity models. Depth migration for an earlierproject used a simple velocity model, and produced an unclear image of the top of the Rotliegend sand-stone under a complex fault (left). Depth migration with the newer, more detailed velocity model gives amuch clearer image of the potential reservoir interval (right).

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9. Kemme M, Brown G, VanBuuren N and Greenwood M:Depth Imaging Unfolds Complex Geology and ImpactsReservesThe Q4 Story, Transactions of the EAGE 63rdConference and Technical Exhibition, Amsterdam, TheNetherlands, June 1115, 2001, paper P071.

Spring 2002 11

Building Reserves through Depth ImagingIn another North Sea development, operatorsused depth imaging to improve delineation ofreserves and increase reserve estimates.

Clyde Petroleum and partners recentlydeployed state-of-the-art depth imaging in arenewed effort to explore, appraise and extendexisting gas discoveries in Blocks Q4 and Q8 ofthe Dutch North Sea (right). The recently discov-ered Q4 gas fields lie in a complex inversion zone(once low-lying, now upthrust along reactivatedfaults) bounded by a series of major NW-SE-strik-ing faults. The new fields are on a trend with twoproducing gas fields in the Q8 block. Before ClydePetroleum began operating the block, seven drywells had been drilled on shallower prospects.

The tectonic history had produced highlydeformed structures, and early conventional seis-mic processing gave suboptimal results. After thedrilling of the first successful exploration well, a new program called for a comprehensive 3D prestack depth migration, followed by com-plete reinterpretation.9

Time Imaging Depth Imaging

> Complex Rotliegend structure revealed by depth imaging. A disrupted interval in the time-migratedsection (left) is difficult to interpret. In the depth-migrated image (right), this becomes identifiable as apop-up of the Rotliegend formation.

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> Gas reservoirs (red) operated by Clyde Petroleum Exploratie BV in the Q4and Q8 blocks of the Dutch sector of the North Sea. Color-coding showsregions with different tectonic histories.

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The complex history of normal, reverse andlateral movements had placed the basin fill ontop of the reservoir block. Time-migrated imagesof these steeply dipping structures were limited in quality, and fault positioning was questionable. Image ray-tracing and borehole-seismic results indicated that lateral fault mis-positioning could be as much as 300 m [1000 ft],depending on the overburden velocity model.

The prestack depth-migration project was ini-tiated to better understand the structural frame-work and correctly position faults, with theexpectation that the results could have a strongimpact on the size of the structure and the plan-ning of the development wells.

Four 3D data sets, approximately 400 km2

[154 sq. miles] of seismic data, were input to theprestack depth migration. Each data set was pro-cessed through a similar, conventional prepro-cessing flow with emphasis on noise reductionand multiple attenuation. Although the individualdata sets had different orientations, no resam-pling was required. Phase matching and ampli-tude compensation were applied to each surveyto match all surveys to a common base.10 Eachdata set was depth migrated individually andmerged after migration, but before stack.

Due to the complex nature of the geology,major velocity contrasts were expected.Therefore, the traditional top-down, layer-strip-ping approach to velocity modeling was not con-sidered adequate.

The structural model indicated that the 3Dvelocity model could be divided into five separateNW-SE-trending velocity blocks, with up to sixvelocity layers below the area-wide Tertiary layeron top (below). Within each block, velocity wasdetermined layer by layer, but the inclination ofthe fault blocks dictated the order in which thevelocity model should be builtfrom southwestto northeast.

Typically, stacking velocities would be used toderive initial interval velocities for a particularlayer. However, due to low confidence in thestacking velocities in this complex area, a modelbased on well data was used. A range of velocitymaps based on the starting velocity was used tooutput a 3D prestack depth-migrated grid of in-lines over the target area.11 A final velocity mapfor the target layer was then derived by interac-tively picking on the depth-migrated commonimage-point gathers.12 Finally, a 500-m [1640-ft]grid of 3D prestack depth-migrated in-lines andcrosslines was generated. These lines were used

to interpret the target horizon in depth, for inclu-sion in the velocity model.

This procedure was iterated layer by layerwithin each fault block until the base horizon hadbeen inserted into the velocity model. Then, thefinal velocity model was used to generate a full3D prestack depth-migrated volume on a 25-m by25-m [82-ft by 82-ft] grid. Residual moveout correction was performed, the data were stacked, and appropriate poststack processingwas applied.

The new depth data showed notable improve-ments over the time-migrated data, andincreased the interpreters understanding of thestructural model and confidence in the fault posi-tioning (next page, top). The prestack depthmigration enabled targeting of the second explo-ration well near a major fault without risk ofencountering a reduced reservoir section, andrevealed that the position of the fault was fartherto the west, increasing the reservoir volume. Thisimproved imaging also had a significant impacton the interpretation of the eastern boundingfault. Because of poor imaging of the tradition-ally migrated seismic data, this fault had beenimaged as an easterly dipping normal fault.However, the superior resolution of the newimages shows that the reservoir-bounding faultis actually a westerly dipping reverse fault,adding an extra fault block of gas-bearing reservoir.

The updated structural interpretation resultedin an increase of almost 50% in gas initially inplace (next page, bottom). Additionally, betterseismic definition decreased uncertainty in thereserves estimate and allowed for detailed inter-pretation of faults within the reservoir, reducingthe risk of leaving compartments undrained.

The robust methodology followed throughoutthe project allowed the construction of an accu-rate velocity model for this complex area. Thesubsequent 3D prestack depth-migrated volumeprovided a significant improvement in the qualityand confidence of the seismic image. As a resultof the improved seismic quality, not only did theapparent volume of the structure increase signif-icantly, but also the better data quality resultedin a much more detailed interpretation ofintrareservoir faults. This allowed for more reli-able planning for three to five future develop-ment wells. The Q4-A field came on-stream inDecember 2000, only 212 years after the firstexploration well was drilled.

12 Oilfield Review

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> Velocity model for the Q4 reservoir blocks. Steeply dipping faults laterally juxtapose con-trasting velocities and place high-velocity layers on top of lower velocity layers. The red boxdelineates the area of interest.

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Spring 2002 13

Prestack Depth Migration on LandMany onshore prospects have the same imagingproblems encountered offshore, but untilrecently, land-based seismic campaigns wereless successful at imaging complex structures.However, depth-imaging projects on land arenow showing the same level of improvementover time-based methods as their Gulf of Mexicoand North Sea counterparts.

Exploration in south Texas is notorious forcomplications caused by complex structures over-lying potential reservoirs. Faults create shadowsthat obscure the shape and disposition of deeperlayers. Imaging targets in fault shadows is achallenge with time-migration techniques, butdepth migration gives much clearer pictures andmore geologically reasonable features.

10. Phase and amplitude of seismic traces are affected bythe timing and power characteristics of the acquisitionsource and by processing, which may vary from one survey to another. Combining data sets from differentsurveys requires phase and amplitude of all data sets to be matched.

11. An in-line is a seismic line within a 3D survey parallel tothe direction of towed-streamer acquisition. A crosslineis a seismic line perpendicular to the direction of survey acquisition.

12. A common image-point (CIP) gather is the set of alltraces that reflect at the subsurface point being imaged.A CIP gather is created by searching over all possiblerays in the acquisition geometry and collecting thosethat reflect at the point of interest.

Time Imaging 1996 Prestack Depth Imaging 1999

GWC

> Comparison of interpreted time- and depth-migrated seismic lines over the reservoir in the Q4 block. Interpretation of the time-migrated image (left)shows a block of reservoir bounded on the west by a thrust fault (yellow), and on the east by an easterly dipping normal fault (black). Interpretation of thedepth-migrated image (right) changes the picture. The new interpretation raises the thrust fault (white line), adding volume to the reservoir on the west. Thenormal fault on the east is no longer considered a bounding fault. The reevaluated reservoir boundary is a westerly dipping reverse fault (red), previouslynot recognized. The approximate gas-water contact (GWC) is indicated.

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< Increase in gas initially in place resulting frominterpretation of depth-migrated seismic data.Interpretation of depth-migrated seismic datamoved faults and added roughly 50% to the gasreserves in this reservoir. Old fault interpretationsare shown in black; new fault interpretations areshown in blue. The increase in reservoir size isshown in pink.

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One example of benefits gained throughprestack depth migration is from a regional, 100-sq. mile [256-km2] WesternGeco multiclientsurvey in south Texas. A conventional time-migrated image across a large normal faultshows some of the typical problems seen in thisarea (above). A pronounced false anticline, orpull-up of the seismic reflections, appearsbeneath the fault on this section. Also, the reflec-tions beneath the fault appear to be broken andhave less continuity than reflections on the rightside of the fault, particularly along the inter-preted horizon.

These imaging problems are caused by thejuxtaposition of rocks of different velocities onopposite sides of the fault (next page, top left).The layers on the upthrown, or left, side of thefault, although older than the layers on the right,are overpressured, and so have lower seismicvelocities. The lateral velocity contrasts causeseismic rays to bend as they cross the fault. Ray bending distorts the seismic image in the time domain.

The depth-migrated section shows a differentpicture. The reflections in this section dip lesssteeply on the left side of the fault than do thecorresponding reflections in the time-migratedsection. The false structural high has diminished,and reflection continuity is improved. An inter-pretation of the depth-migrated section producesa different depth and shape to the layers beneaththe fault, potentially yielding a different explo-ration target.

Depth migration has been successful in otherparts of the world where land-seismic results areknown to be problematic. WesternGeco has performed 3D depth-imaging projects in many ofthe worlds oil-producing countries, includingVenezuela, Bolivia, Argentina, Germany, Russia,Kazakhstan, Egypt, Libya, Kuwait, the United ArabEmirates, Syria, China, Australia and Nigeria.

Reaching Full Potential Todays methods are more accurate than earlierones, but the full potential of depth imaging hasnot yet been reached. The limitations to over-come center around creation of the velocitymodel, deciding what type of migration producesthe best images, and the time required for com-pletion of depth-imaging projects.

Several factors can complicate the model-building process. One that has received recentattention is anisotropy. Much of the subsurface isanisotropic in some physical property, such aselastic properties, permeability or electromag-netic properties.13 The simplest form of elasticanisotropy is called transverse isotropy (TI). Thisoccurs when the seismic velocity has one valueparallel to bedding and a different value perpen-dicular, or transverse, to bedding. In typical casesof TI anisotropy, velocity parallel to bedding isgreater than transverse velocity.

Usually, seismic data processing ignoresanisotropy. However, the effects of stronganisotropy can produce a suboptimal data set ifnot taken into consideration. Ignoring anisotropycan result in vertically and horizontally misposi-tioned structures.

The effects of anisotropy can be seen as anonhyperbolic shape in the arrivals from a flatreflector (next page, top right). Traces from longoffsets arrive earlier than predicted from a modelwith isotropic velocity because they have trav-eled longer in the faster, horizontal direction.

Anisotropy can be incorporated into a prestackdepth-migration velocity model, with conspicuousresults (next page, bottom).14 Prestack depthimaging with an isotropic velocity model producesa fairly clear image of the sediment layersuptilted by a North Sea salt intrusion. However,the layers in the shadow of the salt overhang arenot as clear as they could be, and the gently dip-ping layers on the lower flank of the salt show amis-tie with formation depths measured in a well.Prestack depth imaging with a model thatincludes 10% anisotropy in the overburden produces a clearer image and one that ties withwell data.

Identifying which imaging problems requireanisotropic velocity models and which ones aresimply displaying velocity heterogeneity willbecome easier as more areas are tested.

Processing experts debate which type ofmigration is best for imaging extremely complexvolumes. Prestack Kirchhoff migration has beenparticularly effective in salt and subsalt imagingin the Gulf of Mexico, but sometimes it has diffi-culty imaging features under rugose salt bodies.Because this algorithm uses ray tracing, smallerrors in the shape or location of the salt inter-face can cause migration artifacts.

14 Oilfield Review

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> A time-migrated (left) and depth-migrated section (right) from south Texas. In the time-migrated image, velocity complexities cause a false anticlineimmediately to the left of the fault plane denoted by arrows. Also, the reflections on the left side of the fault appear to be broken and have less conti-nuity than reflections on the right side of the fault. The depth-migrated section shows gently dipping and continuous structures in the fault shadow.The false structural high seen in the time-migrated data has become smoother, and reflection continuity is improved.

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Spring 2002 15

In such areas, finite-difference prestackmigration can provide effective imaging. Thisapproach uses wavefield extrapolation instead ofray tracing, and can produce better images.15

Efficiency gains and the use of larger com-puter systems have shortened project cycle times.But service companies continue to be pressuredto depth-image larger areas and to do it quickly.Oil companies and contractors should share theresponsibility to define realistic time frames.

Depth migration brings a viable solution tocomplex imaging problems. After seeing the dif-ference between depth-imaged data and conven-tional time-imaged sections, operators oftenchange their interpretations and plans, whetherfor prospect exploration or reservoir develop-

ment. Furthermore, seeing the difference in oneseismic section forces the realization that allother data acquired in complex areas probablydeserve a second look. Some operators nowinsist on depth imaging before drilling in deepwater or other high-risk areas.

Other operators are reluctant to apply depthimaging because of the costs involved in acquir-ing and processing target-specific data. To them,it appears that this technology is only for thesuper-major operators. However, it is possible touse depth imaging in a cost-effective manner onmulticlient projects to improve understanding ofregional geological petroleum systems. TheWesternGeco approach to applying depth imag-ing on speculative regional-scale data sets is

helping make the technology available to operat-ing companies of all sizes.

As more operators gain experience with thetechnique, the process will become more effi-cient. Experts predict that in the future, essen-tially all seismic data will be depth imaged. LS

13. Armstrong P, Ireson D, Chmela B, Dodds K, Esmersoy C,Hornby B, Sayers C, Schoenberg M, Leaney S and Lynn H:The Promise of Elastic Anisotropy, Oilfield Review 6,no. 4 (October 1994): 3647.

14. Bloor R, Whitfield P and Fisk K: Anisotropic PrestackDepth Migration and Model Building, Transactions ofthe EAGE 63rd Conference and Technical Exhibition,Amsterdam, The Netherlands, June 1115, 2001, paper A-01.

15. Albertin U, Watts D, Chang W, Kapoor SJ, Stork C,Kitchenside P and Yingst D: Improving Near-Salt-FlankImaging with Shot-Profile Wavefield-ExtrapolationMigration in the Gulf of Mexico, to be presented at theEAGE 64th Conference and Technical Exhibition,Florence, Italy, May 2730, 2002.

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> Depth-migration velocity model for south Texas survey, showing the faultinterpreted on seismic data.

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> Comparison of arrival times versus offset for anisotropic and an anisotropic layer. If the layerwere isotropic, the arrivals would define the redcurve, and if the layer were anisotropic, thearrivals would define the black curve.

Isotropic Depth Imaging Anisotropic Depth Imaging

Well topWell top

> Prestack depth imaging in the North Sea with an isotropic (left) and an anisotropic (right) velocity model. Including 10% anisotropy in the velocity of theoverburden helps to produce a clearer image of the layers that are truncated against a salt intrusion and produces a better depth match to well data.

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