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A 3-D Seismic Case History Evaluating Fluvially-Deposited Thin Bed Reservoirs

in a Gas-Producing Property

Article  in  Geophysics · November 1994

DOI: 10.1190/1.1443554

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GEOPHYSICS, VOL. 59, NO. 11 (NOVEMBER 1994); P. 1650-1665, 22 FIGS.

A 3-D seismic case history evaluating fluvially depositedthin-bed reservoirs in a gas-producing property

Bob A. Hardage* Raymond A. Levey*, Virginia Pendleton‡,James Simmons*, and Rick Edson*

ABSTRACT

We conducted a study at Stratton Field, a large Friogas-producing property in Kleberg and Nueces Coun-ties in South Texas, to determine how to best integrategeophysics, geology, and reservoir engineering tech-nologies to detect thin-bed compartmented reservoirsin a fluvially deposited reservoir system. This studydocuments that narrow, meandering, channel-fill res-ervoirs as thin as 10 ft (3 m) and as narrow as 200 ft(61 m) can be detected with 3-D seismic imaging atdepths exceeding 6000 ft (1800 m) if the 3-D data arecarefully calibrated using vertical seismic profile(VSP) control. Even though the 3-D seismic imagesshow considerable stratigraphic detail in the interwell

spaces and indicate where numerous thin-bed com-partment boundaries could exist, the seismic imagescannot by themselves specify which stratigraphic fea-tures are the flow barriers that create the reservoircompartmentalization. However, when well produc-tion histories, reservoir pressure histories, and pres-sure interference tests are incorporated into the 3-Dseismic interpretation, a compartmentalized model ofthe reservoir system can be constructed that allowsimproved development drilling and reservoir manage-ment to be implemented. This case history illustrateshow realistic, thin-bed, compartmented reservoirmodels result when geologists, engineers, and geo-physicists work together to develop a unified model ofa stratigraphically complex reservoir system.

INTRODUCTION

The Bureau of Economic Geology at The University ofTexas at Austin has completed several research studies tobetter understand the internal architecture of complex, het-erogeneous oil and gas reservoir systems (Finley et al., 1992;Levey et al.,1992b). One of these research efforts is theSecondary Gas Recovery (SGR) project, which is an ongoingstudy to determine if reservoir compartmentalization inolder producing properties creates gas accumulations thathave either not been contacted, or not been effectivelyproduced, by the perforated intervals in production wells(Sippel and Levey, 1991). The primary focus of this SGRproject is to determine how the depositional process anddiagenesis, rather than structure, contribute to reservoircompartmentalization. Consequently, the field studies aredone in producing intervals that have minimal faulting be-cause faulting introduces a reservoir compartmentalizationthat overprints and complicates any compartmentalization

effects inherited from the depositional system. The studiesare also done in older producing properties because suchfields usually have enough well-by-well production historyand pressure documentation to confirm whether or notreservoir compartment boundaries are present (Jirik, 1990;Kerr, 1990; Kerr and Jirik, 1990; Levey et al., 1992a).

This case history summarizes the results of a SGR fieldstudy that analyzed how fluvial deposition affects gas reser-voir compartmentalization. We performed this study in aportion of Stratton Field in Kleberg and Nueces Counties ofSouth Texas. The stratigraphic interval we studied was theOligocene Frio Formation, a thick, fluvially deposited sand-shale sequence that has been a prolific gas producer inStratton Field and in several other fields along the FR-4depositional trend (Figure 1). The regional structure andstratigraphy of the Frio system are well documented byNanz (1954), Galloway (1977, 1982), Han and Scott (1981),and Galloway et al. (1982) and will not be repeated here.

Manuscript received by the Editor April 18, 1994; revised manuscript received June 15, 1994.*Bureau of Economic Geology, The University of Texas at Austin, Austin, TX.‡Formerly Bureau of Economic Geology, The University of Texas at Austin, University Station, Box X, Austin, TX; presently, IntegrityGeophysics, 1503 Palma Plaza, Austin, TX 78703-3434.© 1994 Society of Exploration Geophysicists. All rights reserved.

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3-D Seismic Thin-bed Case History 1651

THE STUDY SITE

We confined our study to a 7.6-mi2 area (Figure 2) where3-D seismic data were acquired in this SGR effort. A largenumber of wells, some as old as 40 years, existed inside this3-D grid, and the logs recorded in these wells allowed us tomake a reasonably thorough geologic analysis of the Frioreservoirs. As shown in Figure 2, we acquired additionaldata in several wells (the circled dots) to supplement thehistoric well log, production, and reservoir pressure databases. These supplemental data consisted of modern welllogs, cores, and various pressure tests. Vertical seismicprofile (VSP) data were recorded in two closely spaced wellsinside the triangle shown near the center of the 3-D grid.

3-D SEISMIC DATA ACQUISITION

The 3-D seismic data were recorded across the study areain four overlapping swaths (Figure 3). Each swath consistedof six east-west receiver lines spaced 1320 ft (402 m) apart.The source lines were oriented north-south, spaced 880 ft(268 m) apart, and extended from receiver line 2 to receiverline 5 of each swath. The recording began at the south end ofthe study area (swath 1, Figure 3a) and rolled northward.When all of the vibrating points (VPs) shown in swath 1 wererecorded, swath 2 was created by dropping the southernthree receiver lines and adding three receiver lines on thenorth side of swath 1. This modification allowed the VPs tocontinue northward as continuous source lines (Figure 3b).In the southern part of the grid (swaths 1 and 2), the sourcelines were straight and uniformly spaced because bulldozerscould be used to clear lanes through the mesquite-coveredproperty. In the northern portion (swaths 3 and 4), permit-ting restrictions prohibited the use of bulldozers, and thesource lines followed irregular paths along existing roads andlanes (Figures 3c and 3d).

FIG. 1. Map of the prolific Frio FR-4 gas trend in south Texasshowing the location of Stratton Field.

We stationed receiver groups at intervals of 110 ft (34 m).Each array consisted of 12 inline geophones spanning adistance of 110 ft (34 m) centered on the receiver flag. Sourceflags were positioned at intervals of 220 ft (67 m). At eachVP, eight linear sweeps (l0-120 Hz) were generated andsummed using a 4-vibrator array symmetrically positionedrelative to the source flag. This geometry created a grid of110 ft x 55 ft (34 m x 17 m) stacking bins in which a stackingfold of 20 existed over most of the image area. Beforemigration, a trace interpolation was done in the source linedirection to reduce the bin size to 55 ft x 55 ft (17 m x 17 m).The final processed data had an effective bandwidth of 10 to80 Hz in most of the Frio interval.

FIG. 2. Generalized map of the study area. The solid dotsshow existing production wells, many drilled at 40-acrespacings. The circled dots locate wells where additionalgeologic and engineering control was acquired in the form ofmodern logs, cores, orressure tests. The 3-D seismic areais approximately 7.6-mi2. VSP control data were recorded intwo closely spaced wells inside the triangle near the center ofthe 3-D seismic grid.

1652 Hardage et al.

FIG. 3. The 3-D seismic data were recorded in four overlapping receiver apertures, referred to as swaths 1, 2, 3, and 4. Eachaperture consisted of six east-west receiver lines spaced 1320 ft (402 m) apart. In each swath, north-south source lines spaced880 ft (268 m) apart, extended from receiver line 2 (circled) at the south to receiver line 5 (circled) at the north. Receiver groupswere spaced 110 ft (33 m) apart, and source points were spaced at intervals of 220 ft (67 m). Data recording began at the southend of the area using swath 1 (panel a) and ended at the north end with swath 4 (panel d). To convert from one swath to thenext, the three southernmost receiver lines of the recording aperture were dropped, and three receiver lines were added to thenorth side. The solid dots show only key wells, not all wells.

3-D Seismic Thin-bed Case History 1653

THIN-BED INTERPRETATION PROCEDURE

The emphasis in this case study was to demonstrate howgeologic and engineering data are essential in interpretingdepositionally generated reservoir compartment boundariesin 3-D seismic images. The seismic interpretation at StrattonField was particularly challenging because most of the Frioreservoirs were thin [< 15 ft (5 m)], and they were closelystacked, in some areas separated only 10 ft-15 ft (3 m-5 m)vertically. These conditions required precise calibration ofstratigraphic depth-versus-seismic traveltime to extract adepositional strata1 surface from the 3-D data volume thatwould reliably depict the area1 distribution of a particularFrio thin-bed reservoir.

Thin-bed depth-versus-time calibration

We used VSP as the primary measurement to define wherea specific thin-bed reservoir was positioned in the 3-Dseismic data volume. The locations of the two VSP calibra-tion wells we used are shown in Figure 2. The zero-offsetVSP data recorded in one of these wells were used toestablish the precise depth-versus-time control needed forthe thin-bed interpretation. These VSP data are shown inFigure 4, where the zero-offset image is spliced into anorth-south vertical slice from the 3-D data volume passingthrough the VSP well. Also shown in the figure is a graphicrepresentation of the stratigraphic column penetrated by theVSP well. Only producing or potentially producing Frioreservoirs are shown in this diagram, and not all of thereservoirs are labeled by name. The top and base of eachreservoir are accurately positioned in terms of two-way VSPtraveltime, and since there is no difference in the VSP and3-D time datum in this instance, the reservoirs are alsocorrectly positioned vertically inside the 3-D seismic datavolume at the VSP well.

Using these VSP traveltime control data, we knew exactlywhere each thin-bed reservoir belonged in the 3-D seismicreflection waveform at the VSP well. We then extended thisthin-bed calibration away from the VSP well and across theentire 7.6mi2 area imaged by the 3-D data.

Defining chronostratigraphic depositional surfaces

The fundamental assumption we made in our seismicinterpretation was that seismic reflections follow chronos-tratigraphic depositional surfaces (Vail and Mitchum, 1977).This assumption means that if we map a continuous seismicreflection event over the entire 7.6-mi2 area imaged by the3-D seismic data, we define a geologic surface that corre-sponds to a fixed, constant depositional time. In otherwords, we define a depositional strata1 surface. We wereable to find two such areally continuous reflection events inthe Frio interval. These two surfaces are shown on theeast-west vertical section crossing the VSP well in Figure 5.

At the VSP control well, the apex of the peak associatedwith the shallower strata1 surface (the orange surface inFigure 5) corresponded to the thick C38 reservoir (Figure 4),and the apex of the peak at the deeper strata1 surface (thegreen surface in Figure 5) correlated with the F11 reservoir.Thus we assumed that the seismic time surface following theapexes of all of the peaks of the orange event defined the

ancient topographic Frio surface at the time when the C38reservoir sediments were deposited. Likewise, we assumedthat the seismic time surface following the apexes of thepeaks of the deeper green event defined the ancient deposi-tional surface associated with the F11 reservoir.

Once the 3-D data volume was flattened relative to one ofthese two reference strata1 surfaces, we further assumed thatany horizontal time slice in this flattened data volume alsofollowed an ancient Frio depositional surface, as long as theseismic reflection character in the immediate neighborhoodof the time slice was time-conformable with the reflectioncharacter in the immediate vicinity of the reference surfaceused to flatten the data volume. In our opinion, the entireFrio section inside the 7.6.mi2 3-D grid was seismicallyconformable to one of the two seismic reference surfaces wecreated.

The thin-bed interpretational philosophy we followed canbe summarized as follows:

1)

2)

3)

4)

5)

Choose one or more areally continuous Frio seismicreflections that can be used as reference surfaces toflatten the 3-D seismic data volume. Specifically, wepicked two such reflection events: the green and orangesurfaces shown in Figure 5.Use VSP data to define the stratigraphic depth corre-sponding to the peak (or trough) time of each selectedreference strata1 surface. We found that the shallow(orange) reflection peak time correlated with the C38reservoir at our VSP control well, and the deeper(green) reflection peak time correlated with the F11reservoir.Flatten the 3-D seismic data volume relative to one ofthe reference strata1 surfaces. In the immediate neigh-borhood of the reference surface, this procedure re-stores the flat, no-dip, surface topography that likelyexisted at the time the meandering, fluvial channelenvironment deposited the Frio sediments associatedwith that seismic reference reflection.Make horizontal time slices through this flattened seis-mic data volume only in time windows in which theseismic reflections are conformable to the seismicreflection associated with the flattened reference sur-face. These time slices are then assumed to followindividual, fixed, depositional surfaces because theconformable reference reflection event was assumed tobe a strata1 surface (Vail and Mitchum, 1977).Use the same VSP control that defined where thereference seismic surface was positioned in strati-graphic depth to define where each time slice is posi-tioned in stratigraphic depth. If two thin-bed reservoirsoccur at times and relative to the referencestrata1 surface at the VSP control well, then the depo-sitional surfaces for these two reservoirs are horizontaltime slices at times and in the flattenedseismic data volume.

Following this procedure, we found that in this specificinterpretation problem, where we had many closely spaced(vertically) thin-beds, the VSP-defined position of a particu-lar thin-bed reservoir was rarely at the apex of a reflectionpeak or trough. Invariably, each thin-bed of interest was

1654 et al.

FIG. 5. An east-west vertical slice from the migrated 3-D data crossing the VSP control well, which is atcrossline coordinate 118. The green and orange surfaces follow the two continuous Frio reflection events thatwere used as reference strata1 surfaces for flattening the 3-D data volume. The yellow surface is the deepestFrio reservoir level. Immediately below this yellow surface is the severely faulted Vicksburg section.

3-D Seismic Thin-bed Case History 1655

positioned at some intermediate, often nondescript, phasepoint in the reflection waveform at the VSP control well.

To create a seismic image that emphasized the internalcomplex architecture of a given thin-bed reservoir system,we time-shifted the migrated 3-D data volume first so theproper predefined reference strata1 surface was flat. Then wemade a horizontal time slice through this flattened datavolume at the exact VSP-defined time for the targetedthin-bed, regardless of where that time slice was positionedin the reflection waveform at the VSP control well. We thenassumed that the seismic time surface contained in thishorizontal slice was the fixed depositional strata1 surface

FIG. 6. Seismic reflection amplitude behavior on a strata1time surface that passes through the F39 reservoir at theVSP calibration well.

where that thin-bed unit was deposited. We also assumedthat any seismic anomalies seen on this surface would berelated directly to stratigraphic heterogeneities within thetargeted thin-bed, and to a lesser degree, would be related tostratigraphic variations in thin-beds positioned immediatelyabove and below the target thin-bed.

We now show the results of this thin-bed interpretationalprocedure at Stratton Field and support the interpretationswith geologic and engineering control.

F39 RESERVOIR

The F39 reservoir was the deepest Frio reservoir westudied. The depositional surface for the F39 reservoir(defined by the steps described above) is shown by theyellow horizon in Figure 5. This surface is immediatelyabove the severely faulted Vicksburg section, and we antic-ipated some faulting effects might extend into the lowest Frioand create some nondepositional reservoir compartmental-ization at the F39 level.

The reflection amplitude behavior on our interpreted F39depositional surface is shown in Figure 6. We assumed thered, linear north-south trends near the center of the image tobe residual effects from the deeper Vicksburg faults. Amagnified view of this F39 surface in the vicinity of four keywells is displayed in Figure 7. These wells were critical toour study because we were able to acquire F39 reservoirpressure measurements in all four wells at the same time(Figure 8), and the differences in these static pressures toldus that each well was in a different F39 compartment. Wethen examined the 3-D seismic image and the availablegeologic control to see if these data indicated where theboundaries were that segregated the F39 reservoir into thesedistinct compartments.

Figure 9 displays our interpretation of the available geo-logic control. Our interpretation of the log curves inferredthat the F39 reservoir in each well was deposited in achannel environment that showed some evidence of splaydeposition. These log data, by themselves, do not provide

FIG. 7. Magnified view of the reflection amplitude behavior on the F39 strata1 time surface in the vicinity offour critical information wells.

1656 Hardage et al.

much information about where compartment boundariesmay exist. However, the seismic image does indicate somepossible compartment boundaries. For example, the mostlikely cause of the compartment boundary that separateswell 197 from the other wells is the depositional variationthat created the red/blue (positive/negative) amplitudechanges that trend north-south between crossline coordi-nates 130 and 140 (Figure 7). Similarly, a probable seismicindication of the compartment boundary that segregates well75 from the other wells is the positive-to-negative (red-to-blue) amplitude variations trending north-south betweencrossline coordinates 110 and 120. However, this same logicof looking for inter-well reflection amplitude changes does

FIG. 8. Static pressures in the F39 reservoir measured duringJanuary 1992 in the four wells shown in Figure 7. Thebottom-hole pressure in well 75 was 300 psi at abandon-ment.

not explain why there is a compartment boundary betweenwells 175 and 202, which are only 200 ft (61 m) apart, sincethere is no appreciable change in the reflection phase be-tween these two wells (i.e., there is no color change in thereflection amplitude plot between wells 175 and 202 inFigure 7).

We relied on offset VSP imaging to verify that there was asignificant change in the F39 reservoir seismic reflectioncharacter between wells 175 and 202. One of these VSPimages is shown in Figure 10. The classical VSP-CDP image(right side of Figure 10) revealed a subtle change in the F39reflection waveform in the vicinity of the 175 well, but themost definitive indication of a compartment boundary wasfound by examining the individual reflection traces beforethey were binned. These traces and the VSP-CDP stackingbin overlay are shown on the left side of Figure 10. When theF39 reflection peaks are followed across the binning corri-dors toward well 175 (which is located in the eighth stackingcorridor from the left edge), we find the peaks terminate inthe sixth corridor, at least 50 ft (15 m) short of well 175, andthey do not resume in a robust fashion until corridor 12,some 100 ft (30 m) beyond well 175.

Thus, we believe the VSP data provide seismic evidenceof a compartment boundary between wells 175 and 202 andforces us to reconsider why this boundary is not evident inthe 3-D image (Figure 7). We propose the following expla-nation. The well positions in Figure 7 show only where thewellheads are located, not where the wellbores penetratedthe F39 reservoir. We did not run deviation surveys todetermine the true bottom-hole locations of the wells. Allavailable information simply indicated the holes were verti-cal, and we now believe the assumption of true vertical wellscan lead to interpretational difficulties when the depositionalstratigraphy varies as rapidly in the lateral direction as itdoes in this example. For example, the F39 reservoir in thesewells is at a depth of approximately 6700 ft (2042 m), and at

FIG. 9. Stratigraphic cross-section of the F39 reservoir showing the depositional environments interpreted from log shapes andthe initial bottom-hole pressure (BHP) observed in each well. The date when each well was drilled is shown above the BHPvalue. The log depths are measured from KB and the curves are shifted to align on a stratigraphic datum.

3-D Seismic Thin-bed Case History 1657

this depth, a 1 degree deviation from vertical is a horizontalmovement of approximately 120 ft (37 m). If a wellbore iswithin 3 or 4 degrees of vertical, most people define the wellto be vertical. An inspection of Figure 7 shows, however,that the borehole for either well 175 or 202 has to deviateeastward only 100 ft (30 m) or so to move that wellbore froma red zone (positive reflection amplitude) to a blue zone(negative reflection amplitude). Thus, the 3-D seismic imagemay be revealing the compartment boundary between wells175 and 202 if we knew exactly the inline/crossline seismiccoordinates where the wellbores intersected the F39 reser-voir .

Our conclusion from analyzing the seismic, geologic, andengineering data associated with the F39 reservoir is that wecan seismically detect F39 reservoir compartments, at leastin the vicinity of wells 75, 175, 197, and 202, but we mustinterpret the seismic image with the assistance of reservoirpressure data to infer which of the many stratigraphicchanges revealed in the seismic image are most likely to bethe compartment boundaries.

F37 RESERVOIR

The F37 reservoir was approximately 20 ft (6 m) above theF39 reservoir in our VSP calibration well, which is atwo-way traveltime difference of only 4 ms. Using thepreviously described thin-bed interpretation procedure, wecreated a time slice through our flattened 3-D data volume4 ms above the F39 strata1 surface. This F37 surface isdisplayed in Figure 11. Comparing this image with theF39 surface (Figure 6), we saw red, linear north-southchannels in the central part of the F37 image similar to thoseobserved in the F39 image, implying that Vicksburg faultingwas still controlling sedimentation in this part of the field.However, there was a significant difference in the southeastquadrant of the F39 and F37 images. Specifically, meanderchannel features occurred at the F37 level but were notpresent at the deeper F39 surface. We focused considerableattention on this F37 depositional topography and show anenlarged plot of the meander features in Figure 12.

FIG. 10. Offset VSP imaging of the interwell space between wells 175 and 202. The F39 reservoir is imaged by the low-amplitudeblack peaks immediately above the dashed line labeled F39. The VSP geometry allowed stacking bins only 25 ft (8 m) wide tobe used, so well 175 is positioned at the ninth trace in the VSP-CDP image, which is 200 ft (61 m) away from well 202, thereceiver well. In the VSP-CDP image, the F39 peaks exhibit some change in reflection character near the 175 well, but a moredefinitive indication of an interwell stratigraphic discontinuity in the F39 reservoir is provided by the display on the left, whichshows each individual receiver trace before the traces are summed to create the VSP-CDP image. The VSP-CDP stackingcorridors are defined by the superimposed grid of lines sloping up to the right. In this prestack display, the F39 reflection peakdisappears in stacking corridor 6, about 50 ft (15 m) short of well 175, implying an interwell stratigraphic break of some type.

1658 Hardage et al.

strata1at the

FIG. 11. Seismic reflection amplitude behavior on atime surface that passes through the F37 reservoirVSP calibration well. This surface is conformable with, andonly 4 ms above, the F39 strata1 surface (Figure 6).

We made a log-based stratigraphic cross-section of theF37 reservoir across the meander features and continuingsouthward beyond the seismic grid (Figure 13). The deposi-tional environment (either channel or splay) at each well isan interpretation based on log curve shape and was madebefore the 3-D seismic data were recorded.

This initial geologically based interpretation of the F37depositional environments indicates that the meander fea-ture seen in the F37 seismic surface is indeed a depositionalchannel. Specifically, the log interpretation (Figure 13) im-plies the F37 reservoirs found in wells 189 and 185 weredeposited as channel fill, and the seismic image shows thesewells to be directly atop a meander feature. The initialdepositional interpretation for the extremely thin F37 reser-voir in well 211 was that this wellbore could have penetratedeither splay or channel fill. The splay option is indicated inFigure 13. Because the 211 wellhead is approximately 300 ft(91 m) north of the meander feature (Figure 12), the log-based interpretation of the F37 depositional environment atthe 211 well is also supported by seismic evidence, since thebottomhole location could be either in channel fill or in asplay.

We analyzed pressure histories recorded in several F37reservoirs near these seismic meander features to determineif reservoir compartmentalization existed. These pressurehistories, summarized in Figure 14, show there are at leastthree, and perhaps four, individual F37 reservoir compart-ments in this area of the field. We relied heavily on thesepressure data to guide the interpretation of the thin-beddedF37 reservoirs.

A reservoir model that honors all three data bases-theseismic, the geological, and the reservoir engineering-isproposed in Figure 15. This model assumes that the F37

FIG. 12. Magnified view of the reflection amplitude behavior on the F37 strata1 time surface in the vicinity offour critical information wells. An interpretation of the stacked thin-bed channel features revealed in thisimage follows as Figure 15.

3-D Seismic Thin-bed Case History 1659

reservoir in the southeast quadrant of the 3-D grid is com-posed of three intermeshed channels, labeled A, B, and C,and a grid overlay of seismic inline and crossline coordinatesis provided so these channels can be correlated with featuresin the 3-D seismic image. The location of the F37 strati-graphic cross-section (Figure 13) is shown, but this geologicinformation defines channel locations along only a single 2-Dprofile of the model. The important information again is thereservoir pressure data, because without this engineeringdata there would be no reason to conclude that a 3-channelmodel would be appropriate. Thus, the model places well129 in channel A and well 185 in channel B, which allowsthese two wells to be in different F37 pressure regimes; i.e.,in different compartments (channels). Wells 127 and 161 areproposed to be in channel C, south of the 3-D seismiccoverage. Only one meander loop of this hypothesizedchannel C extends into the 3-D seismic grid. The rapid F37pressure decay observed in well 189 (Figure 14) implies thatthis well is not in pressure communication with well 185,even though both wells are in channel B. For this reason, weshow a stratigraphic variation in channel B where there maybe an intrachannel compartment boundary.

We wish to emphasize that the reservoir model inFigure 15 is hypothetical and may not yet be the correctpicture of the compartmentalized nature of these F37 reser-voirs. However, we do know that the F37 reservoir in thisportion of Stratton Field is segregated into distinct compart-ments, that this compartmentalization must be caused by the

FIG. 14. F37 reservoir pressure histories observed in wellsnear the seismically imaged meander features. These pres-sure decline curves indicate that these wells are positioned inat least three different F37 compartments, labeled as chan-nels A, B, and C (same labeling notation used in Figures 13and 15). There may be an additional, intrachannel, F37compartment boundary in channel system B that segregateswell 189 (the bold Xs) from well 185 (the open circles).

FIG. 13. Stratigraphic cross-section of the F37 reservoir showing the depositional environments interpreted from log shapes andthe initial bottom-hole pressure (BHP) observed in each well. All log curves are depth-shifted to a marker datum. The channelslabeled A, B, and C refer to meander features shown in map view in Figure 15. The northern three wells are inside the 3-Dseismic grid; the southern three wells are not.

1660 Hardage et al.

fluvial deposition because the seismic data show no evidenceof faulting, and that the proposed reservoir model honors allexisting data that provide any information about the F37reservoir system.

We concluded that the seismic image in Figure 12 revealednot just one meander channel system but at least threeintermeshed thin-bed channels, and that again by usingcommon existing reservoir engineering data (i.e., pressurehistories), we were able to use 3-D seismic images to definewhere compartment boundaries most likely existed in theinterwell spaces.

D11 RESERVOIR

Our third example of a compartmented fluvial reservoir iSthe D00 system, which is one of the very thin reservoirimmediately above the D35 reservoir shown in Figure 4Again, using our VSP calibration technique to define theappropriate flattened time slice that equated to thED11 stratigraphic level, we generated the reflection image irFigure 16.

The information in Figure 17 summarizes the D11 geologicand engineering data available in this portion of the 3-C

FIG. 15. Proposed model for the F37 reservoir system imaged in Figure 12. This model honors thestratigraphic cross-section shown in Figure 13 and the pressure history shown in Figure 14. The channels arearbitrarily drawn as A being the deepest and C the shallowest. An intrachannel barrier is proposed nearcrossline, inline coordinates (125, 35) to explain the different pressure behaviors in wells 185 and 189 (seeFigure 14). South of the 3-D seismic coverage area, the boundaries of channels A, B, and C are drawn asdashed lines to show that the channel shapes and positions are highly speculative.

3-D Seismic Thin-bed Case History 1661

FIG. 16. Seismic reflection amplitude behavior on a strata1 time surface that passes through the D11 reservoirat the VSP calibration well.

FIG. 17. Stratigraphic cross-section of D11 reservoirs showing the depositional environments interpreted from log shapes andthe initial D11 reservoir pressures observed in two critical wells (77 and 150). These pressure data show that well 150, drilledin 1983, penetrated a D11 compartment with virgin reservoir pressure. This compartment evidently has no effectivecommunication with the D11 compartment where well 77 was drilled because well 77 was abandoned in 1972 because ofdepleted pressure. Consequently, an intermeshed two-channel reservoir system is proposed for the D11 reservoir level in thisportion of Stratton Field.

1662 Hardage et al.

FIG. 18. Proposed model for the D11 reservoir systemimaged in Figure 16. This model honors the geologic andengineering data summarized in Figure 17 and mimics themeander pattern shown in Figure 16.

seismic grid. The D11 reservoirs in these four analysis wellswere all interpreted from log shape analysis to be channelfill; some log character indicated splay deposition in theyounger channel system. The pressure information wasagain the key information that told us how many reservoircompartments should be seismically imaged. As noted inFigure 17, the oldest production well (77) was drilled in 1956and encountered a reservoir pressure of 1740 psi. This wellwas abandoned in 1972 when the pressure declined touneconomic levels. Wells 135, 150, and 156 were drilled inthe 1980s, and all three wells encountered virgin D11 reser-voir pressure, implying these wells were in a single D11compartment that was depositionally segregated from well77.

We thus interpreted our D11 seismic image with theknowledge that we were dealing with at least two inter-meshed or juxtaposed thin-bed channel systems. The reser-voir model we inferred from Figure 16 is shown in Figure 18.This model honored the geologic information by placing eachof the four wells in a seismically defined D11 feature thatappeared to be a channel and honored the pressure data byplacing wells 135, 150, and 156 in the same channel complexand well 77 in a separate channel system.

We concluded again that fluvial deposition can createcompartmented reservoirs without the stratigraphic sectionbeing faulted, that individual reservoir compartments can beseismically imaged when geologic and reservoir engineeringdata are used to guide the seismic interpretation process, andthat detailed VSP data or their equivalent should be used toprecisely calibrate the location of thin-bedded reservoirs inthe seismic reflection response. This VSP calibration iscritical because when many thin-beds are stacked closetogether, a particular thin-bed seismic response can be

FIG. 19. Stratigraphic cross section of the F21 reservoirs showing the depositional environments interpreted from log shapeanalysis and the initial reservoir pressures (BHP).

3-D Seismic Thin-bed Case History 1663

completely missed if the time slice is mispositioned by only3 or 4 ms.

F21 RESERVOIRS

For our fourth and last example of seismic thin-bedinterpretation of a compartmented reservoir, we show our3-D seismic interpretation of four closely stacked reservoirs:

FIG. 20. F21 reservoir pressure (normalized by depth) versuscumulative gas production for completions A, B, C definedin Figure 19. Because the data points follow a single straightline trend, all three completions are assumed to share thesame reservoir compartment.

F20, F21, F23, and F25. These four reservoirs are extremelythin and overlap each other in a vertical section only 50 ft(15 m) thick (approximately). For convenience, the reser-voirs in this 50 ft (15 m) interval are collectively referred toas the F21 reservoir system.

We focused our attention in the area of wells 130, 164, 176,195, and 201, where we had the geologic and engineeringcontrol shown in Figures 19 and 20. This control showed thatwe were dealing once again with a splay/channel-fill deposi-tional regime (Figure 19) and that wells 176, 195, and 201(completions A, B, and C) produced from the same F21reservoir compartment (Figure 20). Transferring this infor-mation to the seismic image in Figure 21 showed that we hadas much depositional heterogeneity in the interwell spaces atthis F21 reservoir level as we had observed at the F39(Figure 7), F37 (Figure 12), and D11 (Figure 16) levels. Yetthe reservoir pressure behavior implied the F21 reservoirsystem had no interwell compartment boundary whereas theother three reservoir levels (F39, F37, D11) did.

Our proposed model for the F21 reservoir system imagedin Figure 21 is shown in Figure 22. Although the meanderchannels in this model overlay and intersect each other muchas do the channels shown in the models proposed inFigures 15 and 18, pressure data forced us to conclude thatall of the intermeshed F21 channels between wells 176, 195,and 201 (Figure 21) comprise a single reservoir compart-ment, whereas, the intermeshed channels in Figures 15 and18 create distinct reservoir compartments.

We were particularly impressed that thin-bed stratigraphyas subtle as what existed in the F21 reservoirs could berevealed in 3-D seismic images. Note that some of the F21

FIG. 21. Seismic reflection behavior on a strata1 time surface that passes through the F21 reservoir at the VSPcalibration well. Note the stratigraphic resolution in this 3-D image. The intermeshed channels are as narrowas 200 ft (61 m), and log control indicates the channel fills are approximately 10 ft (3 m) thick (Figure 19). Thissubtle stratigraphy is imaged even though the channels are at a depth of 6600 ft (2012 m).

1664 Hardage et al.

FIG. 22. Proposed model for the F21 reservoir system imaged in Figure 21. This model honors the availablegeologic control (Figure 19) and engineering control (Figure 20), and duplicates the meander pattern revealedin Figure 2 1.

channels are only 200 ft (61 m) wide (Figure 2 1) and 10 ft(3 m) thick (Figure 19). Yet, by using VSP control to defineexactly how to time slice the 3-D data volume, we could findthese small-scale depositional features even though theywere at a depth of 6600 ft (2012 m) (Figure 19).

In this F21 reservoir study, we concluded that 3-D seismicdata, when properly calibrated using VSP control, can revealthin-bed depositional heterogeneities that are not flow bar-riers even though they appear to be as complex as theheterogeneity where known compartment boundaries exist.This conclusion further emphasized the importance of incor-porating pressure data into the seismic interpretation, forwithout this engineering control we never knew if thestratigraphic variation revealed by the seismic imaging was,or was not, a barrier to lateral fluid flow.

CONCLUSION

We show four examples of seismic thin-bed interpretationin a fluvially deposited gas reservoir and support theseinterpretations with geologic and reservoir engineering data.In three of these examples, the 3-D seismic data reveal

stratigraphic variations where reservoir pressure informa-tion implies that a compartment boundary should exist. Inthe fourth example, we show an equivalent degree of depo-sitional heterogeneity as in the first three cases, yet reservoirpressure behavior indicates that none of these stratigraphicvariations creates a compartment boundary. These examplesillustrate that although fluvial deposition creates numerouscompartment boundaries, determining which seismically im-aged stratigraphic changes are compartment boundaries re-quires that geologic and reservoir engineering data (particu-larly reservoir pressure data) be incorporated into theseismic interpretation.

We found it was particularly important to have an accurateand reliable way to translate thin-bed stratigraphy (known indepth) into precisely defined seismic time windows. We areconvinced that VSP data, when properly recorded andprocessed, are the best information to establish the detaileddepth-versus-time calibration required to seismically distin-guish closely spaced thin-beds. We used this VSP calibrationprocedure to seismically distinguish thin-beds that werevertically separated by as little as 4 ms [i.e., 20 ft (6 m)].

3-D Seismic Thin-bed Case History 1665

ACKNOWLEDGMENTS

Funding for this research was provided by the Gas Re-search Institute under Contract No. 5088-212-1718 and theU.S. Department of Energy under Contract No. DE-FG21-88MC25031. Publication has been authorized by the Direc-tor, Bureau of Economic Geology.

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