Geophysical Interpretation: From Bits and Bytes to the Big Picture

Huw JamesMark TellezHouston, Texas, USA

Gabi SchaetzleinMexico City, Mexico

Tracy StarkExxon Production ResearchHouston, Texas, USA

Workstations transport the seismic interpreter into a three-dimensional world, providing new ways to track and

visualize reservoir geophysical data. This article describes methods and tools that help interpreters make the most

of their time and data to create a likeness of the reservoir that can guide drilling and production decisions.

July 1994

For help in preparation of this article, thanks to JohnBoellstorf, Craig Jarchow, Susan Nissen and Gary Marny,Amoco Production Company Research, Tulsa, Okla-homa, USA; Bobbie Ireland, Frank Marrone, Jorgen Ras-mussen and Julie Rennie, GeoQuest, Houston, Texas,USA; Joe Kelly and Rich Lozier, Geco-Prakla, Stavanger,Norway; Paul Ware, Unocal, Houston, Texas; RobertWithers, ARCO, Plano, Texas.Charisma, CPS-3, DepthMap, GeoCube, GeoViz, IES(Integrated Exploration System), IESX, RM (ReservoirModeling) and SurfaceSlice are marks of Schlumberger.1. For a data processing review see: Boreham D,

Kingston J, Shaw P and van Zeelst J: “3D Marine Seis-mic Data Processing,” Oilfield Review 3 no. 1 (Jan-uary 1991): 41-55.

2. SEG-Y is a digital tape format for data exchange speci-fied by the Society of Exploration Geophysicists.

3. The IES and IESX interpretation systems store 32-, 16- or 8-bit format. The Charisma system stores 16- or8-bit format.

Well logs measure reservoir properties atintervals of a few inches, providing a highdensity of information mostly in the verticaldirection. But the volume of reservoir sam-pled by logs represents only one part in bil-lions. Seismic data, on the other hand,cover the overwhelming majority of reser-voir volume but at lower vertical resolution.A processed three-dimensional (3D) seismicsurvey may contain a billion data pointssampling a couple of trillion m3, and somesurveys are 10 times bigger.1 The geophysi-cal interpreter must handle this massiveamount of information quickly and producea clear 3D picture of the reservoir that canguide reservoir management decisions.

In the overall seismic scheme, interpreta-tion builds upon the preceding work ofacquisition and processing. Fast new waysto simultaneously visualize and interpret inthree dimensions are changing how inter-preters interact with geophysical data. Seis-mic interpretation packages band together acollection of tools designed to simplify seis-mic interpretation and smooth the road frominput to output. GeoQuest’s seismic inter-pretation tools—Charisma, IES IntegratedExploration System and IESX systems—offera variety of levels of user-friendliness andsophistication. These packages complete theprocess in roughly four steps—data loading,interpretation, time-to-depth conversion,and map output. This article takes a look athow they help the geophysical interpreterharness a seismic workstation filled with abillion data points—and make it fun.

Getting Data in the Right PlaceBy the time 3D data arrive at the interpreta-tion workstation, they have already under-gone numerous quality control checks, andare ready to be loaded. The objective indata loading is to ensure that as much of theavailable data as possible is loaded onto thecomputer, and that these data points arecorrectly positioned. Data loading continuesto be simplified by software advances.

Fitting all the data onto the computer hasbeen difficult because disk space has beenexpensive. To work around the problem,most data loading routines convert seismictraces from SEG-Y format to a compressedworkstation format.2 This compression canbe perilous, because it reduces dynamicrange of the trace data. SEG-Y data are usu-ally represented in 32-bit floating point for-mat, which allows a range of +/_ 1037. Datain 16-bit format have a range of +/_ 32,768,while 8-bit format has a range of +/_ 128.3Converting data from 32-bit to 8-bit reducescomputer storage requirements by a factor offour, but also reduces dynamic range.Reducing dynamic range may negate muchof the care and money that went into acqui-sition and processing of the seismic data.Although the dynamic range of compresseddata is usually more than the human eye canperceive, computer-driven interpretation can

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-10,000 -5000 0 5000 10,000Amplitude

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nScaling to preserve critical information during compression from 32- to 8-bit format forloading to a workstation. High-amplitude wiggles outside the zone of interest may satu-rate the amplitude scale, causing lower-amplitude wiggles to disappear (left). High-amplitude wiggles can be clipped during loading, allowing smaller-amplitude data inthe zone of interest to become visible (right). Limiting trace length ignores the large ampli-tudes, but this is risky (far right). Large-amplitude shallow reflections may overprint theirstructure on deeper ones and lead to interpretation disaster if neglected.

nLoading definitionof the 3D volume.Charisma and IES3D data-loadingroutines require ori-entation informa-tion such as thegeographic coordi-nates of the originof the survey,azimuth, order andspacing of inlines,and trace spacing.In this marine seis-mic example, linesthat were shot dur-ing the survey arecalled inline sec-tions. Vertical slicesperpendicular tothese are calledcrossline sectionsand horizontalslices cut at a con-stant time arecalled time slices.

be made to take advantage of 32-bit data.Some specialists recommend that data neverbe compressed, and since disk space isbecoming less expensive, that will eventu-ally become a more widespread option.

When compression is necessary, worksta-tions can help the interpreter do it intelli-gently through scaling (above). Scalingensures that data amplitudes are properlysized so that the most important informationis preserved when trace values are con-verted from SEG-Y format to compressedformat. In the Charisma system, scalingmust be user-controlled and different scalefactors can be tested; this allows flexibility,but usually requires practice. In the IES andIESX systems, scaling is done automatically,trace by trace. The scaling factor is stored inthe header of each trace. The factor is reap-plied to the trace each time it is read fromthe data base. This results in a reconstructed32-bit seismic section, regardless of thestorage format.

Loading seismic data in the right place inthe computer involves assigning a geo-graphic location to each trace. For 3D datathis is simpler than for 2D: inputs are thespatial origin and orientation of the data vol-ume, the order and spacing of the shot lines,

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and the trace spacing (below). From thesefew numbers, geographic coordinates foreach of the thousands or millions of tracescan be computed.

If there are older 2D or 3D data, or offsetseismic profiles (OSPs) to be interpretedwith the currently loaded 3D survey, dataloading becomes more complicated.4 Tracelocations for each 2D line or OSP must beaccessed from separate navigation files orfrom the trace headers themselves. Data ofdifferent vintages, amplitudes and process-ing chains must also be reconciled. This isnot a trivial task, but is greatly eased withtoday’s workstations.

Additional data that can be loadedinclude well locations, well deviation sur-veys, log data, formation tops, stackingvelocities from seismic processing, time-depth data from well seismic surveys andcultural or geographic data such as leaseboundaries or coastlines.

In 3D surveys, the seismic lines shot dur-ing the survey are called inline sections orrows. Vertical slices perpendicular to these,called crossline sections or columns, can begenerated from the inline data. In 3D landsurveys, the acquisition geometry can bemore complicated than marine surveys, but

Oilfield Review

4. An offset seismic profile (OSP) is similar to a verticalseismic profile (VSP) except that the seismic source isnot vertically above the borehole receivers, but offsetat some horizontal distance, to produce a seismic sec-tion near the well.

5. Time slices were introduced in 1975. For backgroundsee: Bone MR, Giles BF and Tegland ER: “Analysis ofSeismic Data Using Horizontal Cross-Sections,” Geo-physics 48, no. 9 (September 1983): 1172-1178.

6. A check-shot survey measures the one-way seismictravel time from a surface source to a boreholereceiver at known depth.

nCharisma workpanel for synthetic seismo-grams (top) and seismic trace polarity con-ventions (inset). Synthetics help interpretersunderstand correlations between seismictraces and log interfaces by displayingboth on a time or depth scale. Here the firstand second tracks show a lithology column(left) displayed with the sonic (black), den-sity (blue) and porosity (yellow) logs. Nextcome acoustic impedance (third track) andits derivative, reflectivity, (fourth track, red).A synthetic trace (third track from right) fol-lows, next to the trace extracted along thedeviated well trajectory from the real seis-mic volume (second track from right) and aseismic section near the well (right).

Maximum

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usually the inline direction is taken to bealong receiver lines. In both cases,horizontal slices cut at a constant time arecalled time slices.5

The way seismic data are stored by differ-ent systems affects the time required to gen-erate new sections and display or performother poststack processing. In the Charismaand IES systems, inline sections, crosslinesections and time slices are stored sepa-rately, so a single data value may be storedup to three times. In the IESX system, everyinline trace is stored only once, decreasingdata storage volume. In such a volume thereis no need to generate crosslines becausearbitrary vertical sections may be cut in anyorientation in real time. Horizontal seismicdata are stored in a separate file.

Until recently, 3D data loading routineswere not user friendly, often requiring acomputer specialist. But new applicationsare beginning to make this step morestraightforward, allowing interpreters to loadtheir data alone or with support over thetelephone. However, most companies stillemploy dedicated data loaders, or use con-tract workers.

Tracking Continuities and DiscontinuitiesNow we come to the real interpretation partof the job—identifying the reservoir intervaland marking, either manually or automati-cally, important layer interfaces above,within and below it. The interfaces, calledhorizons, are reflections that signify bound-aries between two materials of differentacoustic properties. Interpretation alsoincludes identifying faults, salt domes anderosional surfaces that cut horizons.

Some interpreters first pick horizons as faras possible horizontally on a set of verticalsections, then outline faults. Other inter-preters pick faults first, then pick horizonsup to their intersections with faults. Thechoice depends on personal preference andexperience. Horizons shallower than thereservoir should be interpreted becausethey affect horizons below. Interpretation ofhorizons outside the reservoir interval isimportant if they correspond to regionalmarkers that can be picked from logs. Inter-preting several horizons that bracket the tar-get zone may also be used to enhance time-to-depth conversion and give clues togeologic history.

July 1994

Knowing which horizons correspond tothe reservoir comes from previous experi-ence in the area, such as earlier 2D seismiclines. This is usually accomplished by tying3D data to an existing 2D line or well. Tyinga seismic line to a well is done by compar-ing an expected seismic trace at the wellwith real seismic data. This is achieved withsynthetic seismograms—synthetics—createdusing logs that cover the target levels(above). To create a synthetic, the sonic anddensity logs are converted to time, often byusing a check-shot survey.6 Next, the sonicand density logs are combined to give anacoustic impedance log—the product ofvelocity and density. Then, through an oper-

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Anticline Conventional Slices

SurfaceSlice Slices

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nConventional horizon interpretation (top) and SurfaceSlice analysis (bottom), a fast newvolume interpretation tool developed by Exxon Production Research and incorporatedinto GeoQuest’s IESX system. Conventional interpretation tracks the top of a domethrough a series of vertical sections. SurfaceSlice interpretation allows interpreters to scanthe 3D-shape of the dome through horizontal slices that resemble a series of contourmaps. Interpretation can be automatically drawn onto the surface in swaths, increasinginterpretation speed and accuracy.

ation called convolution, a pulse trace thatmimics the seismic source is used to changethe acoustic impedance log into a syntheticseismic trace.

Now it’s time to compare the syntheticwith the seismic data at the well. Geologicboundaries, such as the top of the reservoir,are identified in the original logs. Theboundaries are then correlated with thetime-converted logs, acoustic impedancelog and then the synthetic seismogram.Waveform characteristics of the syntheticare compared with the real seismic trace todetermine the seismic representation andtravel time to the geologic boundaries atthe well location. However, at seismicwavelengths—50 to 300 ft [15 to 91 m]—what appears to be one layer in the seismicsection will normally be several layers inthe logs. A main use, then, of tracking hori-zons in seismic data is not to distinguishthin layers, but to provide informationabout the continuity and geometry ofreflectors to guide mapping of layer proper-ties between wells.

To track a horizon, trace characteristicsare followed horizontally across the wholeseismic survey. Common characteristicsused to track an event are the polarity orchange in polarity of the trace. At any time,a trace will be of either negative or positivepolarity, or a zero crossing. A positive polar-ity reflection, or peak, indicates an increasein acoustic impedance, while a negativepolarity reflection, or trough, indicates adecrease in acoustic impedance.7 A zerocrossing is a point of no amplitude, usuallybetween a negative and positive portion of aseismic trace. The amplitude of the peaksand troughs is usually color coded. A widerange of color schemes allows interpretersto accent features to be tracked.

A horizon may be tracked in a variety ofways. Points on the horizon may be manu-ally picked by clicking with the mouse on avisual display of a vertical section. If the seis-mic signal is sufficiently continuous, thehorizon may be tracked automatically usinga tool called an autotracker. Autotracking

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7. These are polarity conventions by SEG standards. 8. Stark TJ: “Surface Slices: Interpretation Using Surface

Segments Instead of Line Segments,” presented at the61st SEG Annual International Meeting and Exhibi-tion, Houston, Texas, USA, November 10-14, 1991.

requires the interpreter to specify the signalcharacteristics of the horizon to be tracked.These include polarity, a range of amplitudeand a maximum time window in which tolook for such a signal. Given a few seedpoints, or handpicked clues, autotrackerscan pick a horizon along a single seismicline or through the entire data volume. Infaulted areas, autotrackers can usually beused if seed points are picked in every faultblock. Horizons picked with autotrackersmust be quality checked manually and mayrequire editing by an interpreter. Still, thetime savings is huge compared to manuallypicking thousands of lines.

If the horizon is difficult to follow, thedata can be manipulated using processingapplications available within most interpre-tation systems. The Charisma processingtoolbox, for example, includes a variety offilters and other options to produce data thatare easier to interpret, without expensivereprocessing. Dip filters suppress noise out-side a specified dip range and highpass fil-ters can reveal discontinuities. Other pro-cesses include deconvolution to extract anideal impulse response from real data, timeshifts to align traces, polarity reversals andphase rotations to match data with differentprocessing histories, scaling to boost ampli-tudes of deep reflections, and time varyingfilters to compensate for wave attenuation.

Some horizons defy reprocessing efforts,and remain too complex to track with con-

ventional autotrackers. Three examples are:(1) reflections that change polarity along thehorizon in response to a lateral change inlithology or fluid content; (2) a local mini-mum that is positive or a local maximumthat is negative; and (3) horizons that are lat-erally discontinuous. SurfaceSlice volumeinterpretation helps track these tricky hori-zons by displaying what might be thought ofas “thick” time slices (above).8 The Sur-faceSlice application was developed atExxon Production Research and has beenincorporated into GeoQuest’s IESX system.

The SurfaceSlice method can be thoughtof as scanning the 3D cube to create a newseismic volume that contains only samplesthat meet some criteria set by the inter-preter, such as local troughs with a givenamplitude range. Thick slices through thevolume are displayed in a chosen colorscheme. The slices contain only data on thetypes of horizons of interest. SurfaceSliceslices resemble a series of contour maps,and are therefore convenient for geologiststo interpret. Slice thickness is interactivelycontrolled by the interpreter, and is usuallychosen to be less than the wavelength ofthe reflection in order to stay on the chosen

Oilfield Review

27July 1994

nA horizon (top) interpreted using the SurfaceSlice application. A series of six amplitudeSurfaceSlice slices (bottom) shows successive time cuts, each 16 msec thick, from 1500 to1580 msec, that allow the horizon to be mapped from top to bottom. Up to 25 slices canbe viewed at a time.

horizon. Multiple windows show a series ofslices at increasing times in which the hori-zon can be rapidly tracked in areal swathsrather than line by line (left).

Once picked, either manually, by auto-tracking or by SurfaceSlice analysis, thehorizon serves multiple purposes. Shallowhorizons can be flattened to give a renditionof the underlying volume at the time of theirdeposition. A horizon, really a set of timevalues draped on a grid of trace locations,may be linked to a formation marker identi-fied in well logs (below). If the marker hasbeen picked in several wells, this serves as aconsistency check on the seismic interpreta-tion. This link may be used later for time-depth conversion or for extending formationproperties away from wells (see “IntegratedReservoir Interpretation,” page 50).

Faults and other discontinuities may bepicked manually with the mouse in twoways. As in 2D interpretation, classic faultinterpretation is done on vertical sec-tions—either inline, crossline or other sec-tions retrieved at any desired azimuth. Afault picked on one section can be pro-jected onto nearby sections to give the inter-preter an idea where to look for the nextfault pick. Thrust faults and high-angle struc-tures such as salt domes require specialhandling, because a given horizontal loca-tion may have multiple vertical values (nextpage, left). A new way of picking faults,made possible by 3D workstations, allowsthe interpreter to identify faults from discon-

nA seismic horizon (dashed yellow) linked to a formation marker identified in well logs(white squares). Marker depths have been converted to time using a velocity modelobtained from a check-shot survey. Also shown are deviated wells and logs, all con-verted to time for display with the seismic section.

Slice 1500 Slice 1516 Slice 1532

Slice 1548 Slice 1564 Slice 1580

tinuities in time slices, SurfaceSlice outputs,or in the faulted horizon in plan view(above, right).

Another interpretation technique thattakes advantage of the 3D nature of datastorage is called attribute analysis. Everyseismic trace has characteristics, orattributes, that can be quantified, mappedand analyzed at the level of the horizon.And though mapping a horizon is basedmore or less on the continuity of the seismicreflection, attributes can vary in many waysalong the horizon. Traditional traceattributes include the amplitude of thereflection, its polarity, phase and frequency.9These trace attributes were introduced yearsago to highlight continuities and discontinu-ities in 2D seismic section. Now, with theaddition of high-speed 3D workstations,interpreters have the freedom to explorenew types of attributes (right). Attributessuch as the dip and azimuth of horizons caninstantly reveal discontinuities and faultsthat could take weeks to interpretmanually.10 Interpreters are also usingattributes to apply sequence stratigraphy to3D data.11

28 Oilfield Review

nA thrust fault and a salt dome creatingmultiple vertical values at the same hori-zontal locations. This can be accommo-dated by GeoQuest workstations. nMapping faults. Traditionally, faults are picked (top, yellow lines) from a seismic section

and viewed on a horizon map. The Charisma system allows both section and map to beviewed simultaneously, and also brings a new way to pick faults (yellow arrows, bottom)in plan view—from breaks in continuity (black) in the faulted horizon.

nOne horizon, many attributes. This horizon is displayed in plan view with four of itsattributes. Similar to a structural map, two-way time to the horizon (top left) is color codedwith small (shallow) values in red grading to large (deep) values in blue. The horizonamplitude (top right) with large negative values in green, is related to acousticimpedance. Reflection heterogeneity (bottom left), a measure of the trace length within agiven time window, is a different measure of amplitude. Horizon dip (bottom right) gives adetailed view of horizon structure.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaThrust Fault

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The Reservoir Takes ShapeAn advantage of 3D workstations is theirspeed compared to a pencil-and-paper job;autotrackers lift some of the workload frominterpreters, letting them do more in lesstime. Other advantages, such as time slices,SurfaceSlice displays and attribute maps, aretechniques made possible because the datareside in 3D on a workstation. But the seis-mic sections are still 2D representations of3D information, and interpreters still per-form quantitative interpretation in 2D.

This is changing as more interpreters usethe full 3D-visualization capabilities of newworkstations.12 The ability to see the datavolume, to zoom and change perspective,gives interpreters new insight into the fea-tures they interpret on horizons. Proper illu-mination makes surfaces easier to under-stand. Changing the light source to a grazingelevation can highlight subtle features suchas faults and fractures, for the same reasonthat the best aerial photos of the earth’s sur-face are shot in early morning or late after-noon to maximize shadows. More advancedworkstations allow interpreters to illuminatehorizons with lights from different locationsand change the reflective properties of sur-faces. Interpreters can spend less time figur-ing out what the structure is, and more timeunderstanding how it can affect develop-ment decisions. A rainbow-colored contourmap, once a marvel of the seismic screen,pales next to a 3D rendering of the samesurface (right).

Structures that appear obscure or discon-nected when examined in 2D seismic viewsmay become clear or continuous in 3D. Orjust as importantly, features that appear con-nected in one perspective may be disjointedin another. Seismic properties between two

9. For an introduction to traditional trace attributes see:Taner MT and Sheriff RE: “Application of Amplitude,Frequency, and Other Attributes of Stratigraphic andHydrocarbon Determination,” in Payton CE (ed):AAPG Memoir 26 Seismic Stratigraphy—Applicationsto Hydrocarbon Exploration. Tulsa, Oklahoma, USA:American Association of Petroleum Geologists (1977):301-327.For information on some new attributes see: Son-neland L, Barkved O, Olsen M and Snyder G: “Appli-cation of Seismic Wave Field Attributes in ReservoirCharacterization,” presented at the 59th SEG AnnualInternational Meeting and Exhibition, Dallas, Texas,USA, October 29-November 2, 1989.

10. Mondt JC: “Use of Dip and Azimuth HorizonAttributes in 3D Seismic Interpretation,” SPE Forma-tion Evaluation 8 (December 1993): 253-257.

11. Risch DL, Donaldson BE and Taylor CK: “SeismicSequence Stratigraphy Technique on a 3D Worksta-tion,” presented at the 25th Annual Offshore Technology Conference, Houston, Texas, USA, May 3-6, 1993.

12. Dewey AD and Boyd CN: “Methods for Transform-ing 3-D Visualization into a Productive ExplorationTool,” presented at the SEG Summer Research Work-shop on 3-D Seismology: Integrated Comprehensionof Large Data Volumes, Rancho Mirage, California,USA, August 1-6, 1993.Marrone FJ, James HE and Lupin SP: “ExploitingVisualization Technology for Geophysical Interpreta-tion,” presented at the SEG Summer Research Work-shop on 3-D Seismology: Integrated Comprehensionof Large Data Volumes, Rancho Mirage, California,USA, August 1-6, 1993.

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nA color-coded contour map of the Gulf of Mexico seafloor (top) and an IESX GeoViz viewof the same surface in 3D (bottom). The 3D GeoViz visualization conveys considerablymore information than the traditional contour map. Appropriate lighting reveals changesin slope of the continental shelf edge—dark regions are steeper than lighter ones. Thecursor activates a report window, recording any desired location.

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deviated wells, either existing or proposed,can be examined by extracting the seismicimage on the twisted plane between them(below). This gives reservoir planners a toolfor verifying reservoir connectivity, whetherfor exploration purposes or for planningimproved recovery campaigns. Well logs,interpreted horizons, faults and other struc-tures can be viewed and moved, alone oralong with the seismic data (next page).

Today, the most powerful 3D visualizationproducts provide real-time interaction withthe 3D image for lighting, shading, rotationand transparency. However, interaction withthe image for creating and editing interpre-tation has typically been limited. For exam-ple, a feature edited in a 3D image must bemanually picked in a separate applicationthat displays the data in a 2D slice. This ischanging with the year-end release of theGeoCube package within the Charisma sys-tem and the GeoViz 5.0 package within theIESX system. Both the GeoCube and GeoVizapplications will permit direct interpretationof horizons and faults in the 3D cube ratherthan on 2D projections, making the most ofthe 3D nature of the data volume.

Time-to-Depth ConversionOnce horizons and structures are inter-preted in time, the next step is to convert theinterpretation to depth.13 The relationshipbetween time and depth is velocity, so avelocity model is needed.14 Different work-station systems exhibit varying degrees ofsophistication in their creation of velocitymodels for time-to-depth conversion. Mostsystems, including GeoQuest’s RM Reser-voir Modeling package and CPS-3 mappingpackage, offer simple geometrical conver-sions based on velocity models that mayvary vertically and horizontally. These con-vert points from time to depth by movingthem in straight vertical lines. The CharismaDepthMap package includes geophysicalmodeling in the form of seismic ray tracingand permits lateral translation of points toperform time-to-depth conversion withincreasing reliability.

If more than one horizon is to be con-verted to depth, an average velocity to eachhorizon must be estimated, or the averagevelocity to the shallowest horizon and thevelocity between each horizon down to thetarget horizon.

In the absence of logs or well seismic sur-veys, seismic stacking velocities can substi-tute for average vertical velocities. Stackingvelocities are derived from seismic data dur-ing processing, and used to combine seis-mic traces to produce data that are easier tointerpret. They contain large components ofhorizontal velocity and are usually availableat 500-m to 1-km [1640 to 3280-ft] spacingacross the survey area. These data are inter-polated to the same sample interval as theseismic time horizon grid. Then the velocitygrid is multiplied by the time grid to give adepth grid. The key limitation of stackingvelocities is their lack of accuracy, espe-cially in regions of complex velocity or ofcomplex structure.

Time-depth data from a check-shot surveygive an accurate vertical velocity model, butonly at the check-shot location. In theabsence of other data, this velocity can beused uniformly across the field to convertthe seismic times to depth. Stacking veloci-ties can be calibrated at the well usingcheck-shot surveys.

A synthetic seismogram built from sonicand density logs can provide a comparisontrace for time-to-depth conversion. Disad-vantages of this technique are the limitedextent of logs—most logs do not provideinformation all the way to the surface—andthe discrepancy between velocities mea-sured at sonic frequencies and those mea-sured at seismic frequencies. Synthetics aremost useful when calibrated with a check-shot survey, which improves the time-to-depth conversion.

Velocity models and images from VSPsare the most powerful data for convertingsurface seismic times to depth. VSPs samplevelocities at more depths than check shots,and unlike synthetic seismograms createdfrom sonic logs, VSPs have a frequencycontent similar to that of surface seismicwaves. And above all, VSPs provide imagesthat can be matched directly to surface seis-mic sections.15

Putting It All on the MapOnce data about reservoir structures arestored, 2D and 3D map images can be gen-erated for reservoir characterization. Sur-faces may be mapped in time, or, if there isa velocity model, in depth. Basic mappingtools for this reside within most seismicinterpretation packages, and there are alsoseparate, stand-alone mapping packagesthat accept seismic interpretations for mapgeneration.

One such package, the CPS-3 system, isdesigned to provide accurate geographicand volumetric information about the reser-

30 Oilfield Review

nA well section—a seismic section reconstructed between two deviated wells (red). Thisdisplay is sometimes called a spinnaker section after the sail of similar shape. Well sec-tions can reduce error in planning horizontal wells and sidetracks from deviated wells,and help correlate logs in deviated wells with seismic data. A seismic section betweenany two trajectories can be extracted from the 3D volume.

voir. Given seismic horizons, faults and for-mation tops from logs, mapping programscreate surfaces that honor all data sets.These packages can also give detailed volu-metric information about the reservoir. Withthese advanced mapping packages, process-ing steps applied in the same way to severalhorizons can be automated by creating a“macro,” a command file that repeats pro-cesses uniformly, saving time. Anotheroption is a running audit of all calculations,so volumetric calculations can be verifiedby operating partners. An advantage of theCPS-3 package is the Full Fault ModelingSystem, which accommodates nonverticalfaults, giving more accurate pay volume cal-culations in faulted reservoirs.

The End of the BeginningAfter weeks or maybe months in the work-station, the seismic interpretation is ready tomove to the reservoir modeling system (see“Integrated Reservoir Interpretation,” page50), then possibly into a fluid flow simula-tor. But the seismic software should not beleft to gather dust until the next project.Although seismic interpretation tools weredesigned to display and interpret seismic

data, they also solve one of the biggestproblems in reservoir characterization—integration and visualization of all final out-put. Results from steps further down theinterpretation chain, such as porosity mapsor acoustic impedance sections from thereservoir modeling package, can be loadedback into the seismic interpretation systemfor viewing and sliced into arbitrary sectionsfor accurate reservoir planning. No moremental gymnastics are required to connectsquiggly lines or separate reservoir compart-ments in the mind.

And as the reservoir model is updated andrefined with new data, the seismic datashould be revisited.16 Analysis of pressuredata might indicate which reservoir levelsare in communication, bracketing the possi-ble displacement on a fault that should bereexamined in the seismic volume. A lookat production rates might turn up a fault thatwas missed in the first seismic interpreta-tion. With an interactive interpretation sys-tem the reservoir model can easily bechanged to incorporate new ways ofthinking, and can evolve throughout thelifetime of the reservoir. —LS

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nGeoViz 3D display of multiple seismic lines, horizons and wells from the Gulf of Mexico.Blue lines are the 3D survey (1). Red lines are the 2D survey (2). Three horizons are dis-played with different attributes; time horizon (3), illuminated horizon (4) and amplitudehorizon with a bright spot in yellow (5). A time slice (6) is displayed near the bottom. Alsoshown are a crossline (7), inline (8), well section (9), well logs (10), markers (11) and afault (12).

13. Most 3D seismic processing yields time-based traces. Advanced processing called depth migrationoutputs traces in depth. For more on migration tech-niques see: Farmer P, Gray S, Whitmore D, HodgkissG, Pieprzak A, Ratcliff D and Whitcomb D: “Struc-tural Imaging: Toward a Sharper Subsurface View,”Oilfield Review 5, no. 1 (January 1993): 28-41.

14. For a tutorial on seismic velocities see: Amery GB:“Basics of Seismic Velocities,” The Leading Edge 12(November 1993): 1087-1091.

15. For a description of the technique see: Miller D andStewart L: “Reservoir Imaging Using VSP-DerivedVelocities: A Case Study,” 58th SEG Annual Interna-tional Meeting and Exposition, Anaheim, California,USA, October 30-November 3, 1988.

16. For an example of how seismic interpretation isrevised with input of reservoir engineering data see:Stewart L: “Closing the Loop: How Reservoir Testing,Production and Simulation Results Feed Back to Seis-mic Reprocessing and Interpretation,” presented atthe SEG Summer Research Workshop on Lithology:Relating Elastic Properties to Lithology at all Scales,St. Louis, Missouri, USA, July 28-August 1, 1991.

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