ABSTRACT

The upper Green River Formation at the Bluebell-Altamont field, Utah (Figure 1) is a tight gas sandreservoir where economic production can be sus-tained only in regions of high natural fracturing. In1994, a demonstration seismic project was conduct-ed at the field to show how exploration for, and thecharacterization of, naturally fractured gas reservoirscan be more effective through the integrated use ofseismic techniques. Study of field exposures, welllogs, and regional stress indicators prior to the seis-mic survey indicated a high degree of preferential ori-entation to the dominant fracture trend at the field.The seismic survey consisted of two crossing, nine-component surface seismic lines and a nine-componentvertical seismic profile. The compression, and shear-wave surface seismic both recorded anisotropies thatwere related to the presence and azimuth of the natu-ral fracturing. The surface seismic results were sup-ported by results from the nine-component verticalseismic profile. This program demonstrates thepotential offered by the use of integrated seismic andgeological techniques for the analysis of both landand marine naturally fractured reservoirs; further-more, it demonstrates the possibilities of reviewingexisting databases containing compression-wavesurface seismic data for fracture information.

NATURALLY FRACTURED GAS RESERVOIRPROGRAM

This study formed part of the Department ofEnergy (DOE) program for the detection and analysis

1392 AAPG Bulletin, V. 83, No. 9 (September 1999), P. 1392–1407.

©Copyright 1999. The American Association of Petroleum Geologists. Allrights reserved.

1Manuscript received March 23, 1998; revised manuscript receivedJanuary 18, 1999; final acceptance January 29, 1999.

2Sedimentary Systems Research Group, University of St. Andrews, Fife,Scotland; e-mail: crb@st-and.ac.uk

3Lynn Inc., Houston, Texas.This work was conducted under Blackhawk Geosciences contract for the

U.S. Department of Energy (DOE) Contract #DE-AC21-92MC28135.Pennzoil E and P is thanked for support and commitment to the project. DavePhillips, Stewart Squires, Mike Jones, and Wallace Beckham are all thankedfor their help during the project and for many invaluable discussions.

The Study of a Naturally Fractured Gas Reservoir UsingSeismic Techniques1

C. R. Bates,2 H. B. Lynn,3 and M. Simon3

of naturally fractured gas reservoirs. The principalgoal of the research program was to expand cur-rent levels of industry development and productionefficiency of natural gas from the extensive tightgas resource base of the United States where low-matrix permeability reservoirs are expected to rep-resent more than one-half of expected domestic gasproduction by 2030 (Watts, 1996). The aim of thisproject was the field demonstration of surface anddownhole seismic techniques for predicting areasof fracturing that can be linked to potentiallyenhanced gas production in reservoirs with low-matrix porosity and permeability.

For the productivity to be enhanced in low-porosity and low-permeability reservoirs, the reser-voir must be extensively fractured (Szpakiewicz etal., 1986; Lorenz and Finley, 1991). The fracturenetworks, however, commonly are not uniformlydistributed throughout a reservoir (Lorenz et al.,1996). Locating zones with high fracture densityprior to a drilling program is desirable so that thesezones can be specifically targeted. High fracturedensity zones of interconnected fractures with suf-ficient aperture to allow the enhanced f low ofhydrocarbons have been linked to zones of anoma-lous, high azimuthal seismic anisotropy (Lynn,1995); furthermore, these zones are characterizedby a dominant open-fracture direction, the orienta-tion of which is controlled by the deformation his-tory of the rock and the current in situ regionalstress regime. To take advantage of a natural frac-ture pattern, a horizontal well would be locatedperpendicular to the dominant fracture direction toprovide maximum drainage potential of the reser-voir. This project compares seismic azimuthalanisotropy data recorded over a naturally fracturedgas reservoir to the geological information aboutfracturing within and around the reservoir.

SEISMIC TECHNIQUES

Most open, natural fractures in the subsurface arenear vertical and are preferentially oriented. Theinfluence of vertically aligned fractures on seismicwaves has been documented in the literature for

many years (Nur and Simmons, 1969; Nur, 1971;Crampin, 1985; Lynn, 1986; Crampin et al., 1989);furthermore, it has been demonstrated that thepresence and properties of these fractures, espe-cially when they are open and filled with fluid orgas, can be mapped using shear-wave seismic tech-niques, such as shear-wave birefringence measure-ments (Mueller, 1991).

When a shear wave enters an anisotropic region,such as a fractured reservoir, it undergoes a phe-nomena known as shear-wave birefringence orshear-wave splitting (Figure 2) (Crampin, 1985).The shear wave splits into two vertically propagat-ing shear waves with the fast shear wave polarizedparallel to the fractures (S1) and the slow shearwave polarized perpendicular to the fractures (S2).To a first-order approximation, the S1 travels at theuncracked shear-wave rock velocity, whereas thevelocity of S2 is a function of fracture density (Lynnand Thomsen, 1990). These two directions, paralleland perpendicular to the fractures, are referred to

as the principal directions or axes of anisotropy.The magnitude of shear-wave birefringence isdetermined from traveltime differences betweenthe fast (S1) and slow (S2) waves and the directionof polarization of S1 is determined by the azimuthof open fracturing and orientation of maximumand minimum in situ horizontal stress (Crampin,1985). Whether the differences between in situhorizontal stress or the fractures related to thisstress are the primary cause of shear-wave splittingcurrently is a subject under intensive research andis not addressed in this paper.

Numerous seismic studies have recorded shear-and compression-wave signals using multicompo-nent vertical seismic profiles (VSP) and multicom-ponent surface seismic techniques (Lynn andThomsen, 1990; Queen and Rizer, 1990; Mueller,1991). These techniques seek to record the fullshear- and compression-wave signature by usingmulticomponent recording. Multicomponentrecording typically involves using receivers with

Bates et al. 1393

Figure 1—Regional sitelocation map for theDepartment of Energy project and generalizedstratigraphic column forthe Eocene upper GreenRiver Formation.

Project Location

Uinta BasinUinta Basin

Piceance Piceance Basin Basin

Uinta Basin

Piceance Basin

U S A

Uinta MtsUinta MtsUinta Mts

Browns Park FMBishop Conglomerate

Duchesne River FM

Uinta FM

Green River FM

Wasatch/Colton FM

Eastern UintaBasin MembersEvacuation Creek Mbr

Parchute Creek Mbr (Oil shale)

Garden Gulch Mbr

Douglas Creek Mbr

Q QQTT5T4

T3

T2

T1

M - POLIG

EC

OC

EN

EUpperGreen River

MahogonyBench

Gas Oil

D.O.E..E. Pr ProjectojectD.O.E. ProjectRooseveltRoosevelt

recording elements oriented in three mutually per-pendicular axes (3 component or 3C) and eitherone component vertically oriented compression-wave sources or with additional compression-wavesources oriented in orthogonal horizontal direc-tions. When three component sources are usedtogether with three component receivers, a nine-component (9C) survey can be acquired. Using 3Creceivers allows the split shear waves to be decon-volved, thus providing the faster (S1) direction andthe magnitude of shear-wave splitting or time delaybetween the split waves in addition to standardcompression wave results and amplitude variationwith offset (AVO) data. The magnitude of the timedelay between S1 and S2 can be calculated by com-paring the arrival times to the same reflectors onseparate S1 and S2 migrated stacked surface-reflec-tion data at common mid-point locations (Mueller,1991). The magnitude of splitting can be calculatedin VSP data in a similar manner by recording thetime delay between S1 and S2 to the same horizon.The arrival time delay between S1 and S2 reflec-tions to the top of a target zone of interest docu-ments the magnitude of splitting in the formationsoverlying the target, whereas time delays through

the target zone of interest give splitting values for thetarget. The polarization directions determined eitherat the surface or in a borehole will give the splittingdirection of the last event through which the shearwaves traversed. Lateral differences in S1-S2 timedelay along a seismic line reveal the lateral changes inrelative fracture density. Although shear-wave studiescan be used to measure significant properties of frac-tured reservoirs, the acquisition and processing ofthe data are complex and thus costly. Historically,the cost of shear-wave surveys has prohibited theirroutine use because typical surveys can be three toeight times more expensive than compression-wave surveys (Lynn et al, 1996).

The magnitude of compression-wave anisotropyin fractured rock is less than that for shear waves;however, it has been demonstrated that a smallamount of gas over water in the open fractures will pro-duce a compression-wave AVO anomaly when the com-pression-wave ray paths are oriented perpendicular tothe fractures (Crampin, 1985; Thomsen, 1986).Figure 2 also shows part of the mode conversionenergy of compression-wave ref lection at anisotropic-anisotropic boundary for reflections par-allel and perpendicular to an open-fracture zone.

1394 Study of a Gas Reservoir

Shear-Wave Source

Compression-Wave Source

OpenFractures

OpenFractures

S2: Polarized fractures

S1: Polarized fractures

KHMAXKHMAX

P

P

SV(S2)

SV(S1)

Figure 2—Schematic representation of shear-wave splittingthrough an anisotropicmaterial and compression-wave conversion to shear waves from reflection at an isotropic-anisotropicboundary. Ray paths forcompression waves areshown both perpendicularand parallel to the dominant open-fractureorientation. KHMAX = maximum horizontal stressdirection (modified fromCrampin, 1985; Lynn,1996).

When the orientation of the compression wave is par-allel to the fractures, the wave mode converts to thefast shear direction S1, but when the compression-wave orientation is perpendicular to the fractures,the wave converts to the slow shear direction S2.Modeling studies by Allen and Peddy (1993) clearlydemonstrated the variation of amplitudes due togas-filled fractures in the Austin Chalk with overly-ing shale. In this Austin Chalk example, the relativefracture density governs the compression-wavereflection coefficients on middle to far offsets onreflection profiles where ray paths are perpendicu-lar to the fractures. In a study by Johnson (1995),the attenuation of compression waves propagatingperpendicular to the fractures (thus crossing thefractures) was found to be greater than the attenua-tion for propagation directions parallel to the frac-tures; therefore, it is necessary to obtain data forray paths both parallel and perpendicular to thefractures to determine the seismic anisotropy usingcompression waves. Unlike shear-wave anisotropystudies where a single wave path can be used todetermine the magnitude of splitting, the dataacquisition for compression waves requires travelpaths through different rock sections, which canintroduce other potential causes of amplitude varia-tions such as heterogeneity in the rock or pore-filltype. Despite these limitations, a major advantageof using compression waves for fracture analysis isthat the cost is much reduced compared to theshear-wave techniques.

For this demonstration project, both shear-waveand compression-wave techniques were tested forsurface seismic and vertical seismic profiling. Thesurface shear-wave seismic yielded splitting varia-tions for every point along the surface lines no mat-ter what the orientation of the lines with respect tothe anisotropy (fractures); however, we wanted toorient the compression-wave seismic nearly paral-lel and perpendicular to the fractures to measurethe largest AVO signatures using this technique.Because compression-wave anisotropy studiesrequire ray paths from more than one azimuth, it isonly at crossing points in lines that appropriatedata are available. In typical two-dimensional (2-D)surface seismic surveys, this information is presentat the tie points of lines. In three-dimensional (3-D)surveys, this information is available at every binlocation provided that the survey is collected witha sufficient range of azimuths.

GEOLOGICAL SETTING

The Bluebell-Altamont field is located in thenorthern part of the Uinta basin, Utah (Figure 1),and has been classified as a fractured, but other-wise tight, gas sand play (Spencer, 1989; Fouch et

al., 1992). The field lies within an asymmetric east-west–trending basin south of the Uinta Mountains with asteep thrust-bounded north flank and a gently slop-ing (1–2°) south f lank. The Uinta basin was thefocus of lacustrine, fluvial, and alluvial depositionfrom the Late Cretaceous to the late Eocene(Johnson, 1985). The Tertiary upper Green RiverFormation represents the last major lacustrinedeposit within the basin before renewed uplift ofthe Laramide structures, such as the Uinta Moun-tains to the north. Lacustrine intervals are repre-sented by lake deltas, beaches, offshore bars,nearshore swamps, and sediments deposited onoxygenated and anoxic lake bottoms. The lake waslarge and deep with a stratified water column locat-ed relatively close to a source area characterized byactive volcanism. Potentially productive sandstonesequences represent deposition in delta channelsand stream mouth bars that were associated withtidal flat/shoreline fine-grained deposits. The sand-stones are classed as quartzarenites with detritalconstituents principally of subangular to subround-ed grains of quartz. The fine-grained deposits aredominantly clastic shale with kerogen (plant frag-ments) and limestone (micrite) with fragments ofthin-shelled pelecypods.

The youngest sediments present are the terrige-nous rocks of the lower Oligocene Duchesne RiverFormation. Significant erosion of these sediments(approximately 4500 m) has created the highlydeveloped badlands terrain at the surface today.Widespread fracturing has been observed in theBluebell-Altamont field (Lucas and Drexler, 1976).Narr and Currie (1982) noted orthogonal joint setsat outcrops in the central and southern parts of thefield, together with monodirectional fractures incores from the field. Using these observations, theydeveloped a stress history model of fracture forma-tion by failure during extension after burial andsubsequent uplift. This model supports the propos-al by Osmond (1965) that the Tertiary rocks of theUinta basin have undergone only a single cycle ofburial, diagenesis, uplift, and denudation. Althoughvarious origins and mechanisms have been pro-posed for fracture development (Stone, 1969;Gries, 1983), their presence is undisputed.

The gas intervals are trapped by a combinationof structural and stratigraphic factors. Situated onthe gently dipping (1–2°) southern limb of a largeregional basin, the Bluebell-Altamont field exists asa small east-west–oriented anticline with approxi-mately 15 m of closure. The gas is trapped in struc-turally updip pinch-outs of the prograding lake mar-gins. Producing intervals consist of fracturedlake-margin sandstones encased by tight shales andcarbonate of the lacustrine deposits. Individualsandstone units range in thickness from about 1.5to 6 m thick and can occur as composite units up

Bates et al. 1395

to 30 m thick. The sands have limited extent in theeast-west or strike direction. The relatively cleansandstones result in fast sonic velocities (4500–5500 m/s), with strong reflections that can be easi-ly correlated between wells using the surface seis-mic data.

Gas is currently being produced from theupper Green River Formation at depths from1980 to 2590 m. At the field, the gas productionis interpreted to be from fractures in sandstoneswith a matrix porosity that is typically less than8% and with permeabilities of less than 1 md. The

low-matrix porosity is a function of the cementa-tion history of the rock. Most of the sands arestrongly cemented with fine-grained dolomite as analteration of micrite, calcite, and quartz (Figure 3A,B, depth 1995 m). Calcite cement generally is poik-ilotopic and occurs either in association with thecalcite grains or without calcite grains. Quartzoccurs as a cement overgrowth. Fractures observedin cores commonly are open but can also be filledwith calcite cement (Figure 3C, D). Figure 3C andD is from core at a depth of 2248 m, where the cal-cite crystal growth is into the open fractures. The

1396 Study of a Gas Reservoir

Figure 3—Core from the upper Green River Formation, Bluebell-Altamont field. (A) Fine-grained poorly sortedsandstone with no significant porosity (1995 m depth); (B) medium-grained poorly sorted calcareous sandstone,minor porosity (blue); (C and D) fine-grained poorly sorted sandstone with a large micrite clast seen as a large darkarea in (C) and in the top half of (D). The clast is crossed by an open fracture and a partially open fracture filledwith calcite. Core from 2248 m depth.

presence of the calcite crystals growing into theopen fractures suggests that the fractures are natu-ral and not drilling induced. The open fractureshave an aperture of at least 10 µm as determined bythe size of calcite crystals, and thus the fracturesthemselves are estimated to be at least this width inthe subsurface. Some of the fractures have greaterwidths in the cores, but it is difficult to estimate ifthis would have been the true width of the fracturein situ because there could have been subsequentstress relief. Gas production rates range fromuneconomic rates of 100 MCFGD from unfracturedreservoirs to economic rates of more than 5000MCFGD in fractured reservoirs. Production hasbeen enhanced in several wells with hydraulic frac-turing of the reservoir.

FRACTURE STUDIES

To obtain optimal seismic data for fracture char-acterization, a database of geological fracture infor-mation was collected prior to the seismic surveydesign. These data are summarized in Table 1 andconsist of fracture information from core, well logs,outcrop fracture mapping, and a literature review ofthe current in situ stress for the region. The orienta-tions of near vertical fractures were mapped on sur-face exposures of the Duchesne River Formation atthe field site, but no attempt was made to recordfracture length because the deeply eroded bad-lands topography inhibited this type of study; how-ever, a fracture was noted in the field only if itslength was greater than 1 m. Fracture informationfrom field mapping showed two dominant trendsapproximately N30W and N65E (Table 1, Figure 4).

Fracture information from well logs was in theform of Formation Microscanner™ (FMS) imagesand well breakout information from caliper logs.Analysis of the FMS images showed a fracture trendin the northwest-southeast direction for the upperGreen River Formation with an east-west trend inthe lower Green River Formation. Well breakoutdata have been used in many studies to infer thedirections of current in situ regional stress (Zobaket al., 1985), where the elongation of the boreholeis measured by four- or six-arm caliper logs. Thelong axis of the ellipse is interpreted to show analignment to the minimum horizontal stress direc-tion with the potential for open natural fracturesperpendicular to this. The FMS images for thisstudy showed that from depths of 2030–2140 m,there was an elongation in the northeast direction,indicating that fractures with a northwest azimuthwould be preferentially open; furthermore, the ori-entation of regional maximum horizontal stresswas determined using deep earthquake focus andother stress indicators by Zobak and Zobak (1991)to be in a direction of N30W.

The presence of gilsonite veins or dykes in thebasin gives other regional information concerningthe trend of natural fracturing in the area. Gilsoniteor Uintahite is a black to green shiny asphalitefound almost uniquely in veins in Utah. The veinsare from 30 cm to 6 m wide and can be many kilo-meters long. Fouch et al. (1992) postulated that thegilsonite is injected as veins subsequent tohydrofracture of the rock perpendicular to the min-imum horizontal stress. This natural hydrofractur-ing is thought to have occurred due to formationwater expulsion from the lower Green RiverFormation. Within the project area, the veins are

Bates et al. 1397

Table 1. Fracture Azimuth Database from Surface Geological Measurements, Seismic Measurements, and RegionalInformation

Azimuth of Azimuth of Location orInformation Dominant Fracture Location (Depth Other Fracture Depth ofType Direction of Information) Directions Information

Field exposure mapping N20–40W 0 m (surface) N60-70E Surfaceof near vertical fractures

Well log, FMS* N20–30W 2000–3320 m East-west >3320 mWell log, Northeast, minimum 2030–2140 m N30W-N10E >3320 mborehole breakout horizontal stress

N45–30WRegional stress, 0 m (surface)Gilsonite veins

Regional stress N30W, maximum 0 m (surface)(Zobak and Zobak, 1991) horizontal compression

Regional stress; N10–20W, 20,000 ft focusearthquake focus maximum horizontal35 mi west compression

*FMS = Formation Microscanner .

oriented dominantly northwest-southeast (Narr andCurrie, 1982).

In summary, the geological and stress informa-tion indicates that there are two major trends offracturing for the upper Green River in the field,namely northwest-southeast and northeast-south-west. Of these two directions, we postulate fromthe stress data that the northwest trend is morelikely to be the azimuth of open fractures.

SEISMIC PROGRAM

The optimal location for the surface seismic linesand VSP in the field was critical to the success ofthe project. The orientation of the surface seismicwas based on the best estimate of the open naturalfracture trend in a northwest direction with seis-mic lines laid out parallel (line 1) and perpendicu-lar (line 2) to this (Figure 4). The final orientationof the two crossing lines, northwest-southeast andnortheast-southwest, also facilitated the acquisitioneffort because a major drainage crossed the areawith a northwest-southeast azimuth. A moredetailed location map has not been provided due toproprietary concerns of the industrial partner.

The final acquisition parameters for the surfaceseismic were determined during a wave test programusing impact sources to test receiver polarities andboth compression-wave and shear-wave Vibroseis™for variations in sweep length and frequency.Compression-wave acquisition for AVO requires long

offsets to record the variations in amplitude due tofracture content. For this project the target reservoirwas at a depth of 1800–2440 m, and therefore offsetsof at least this range were necessary. With shear wavedata, near-vertical travel paths are considered moreuseful for recording split shear waves. Thus, for idealsurvey conditions, one would like to be able to recordfull fold data for both compression waves and shearwaves. Unfortunately, this would have required morerecording channels than were available at the time inthe field. A compromise was made and a reduction infold of the shear-wave data was necessary to accom-modate the 0–2740-m offset range for the compres-sion-wave data. In areas where low shear-wave signal-to-noise ratios are experienced, this compromisecould have had a major impact on the study; howev-er, the wave tests indicated that the signal-to-noiseratio was high for the shear-wave data, and thus itwas better to record more data at far offset for thecompression-wave AVO than to concentrate on thenear-offset shear waves.

The 9C VSP was acquired prior to the 9C surfaceseismic survey at the eastern end of line 2. The fieldresults from this also were used in the planning of the sur-face seismic acquisition parameters. Table 2 summarizesthe 9C VSP and surface seismic acquisition parameters.

9C VSP

The objectives of the 9C VSP were to determinethe time-depth-velocity relationship for split shear

1398 Study of a Gas Reservoir

9C VSP

Line 2

N

0 2000 m

maximumhorizontal stress from borehole elongation

fracturefromcores

gilsonite dykes

fractures fromoutcrops

N

EW

J

K

D

L

M

N

O

B

C

E

F

GH

XX -

Line 1

wells used insynthetic compression-wave study

multicomponentvertical seismic profile

P

9CVSP -

Figure 4—Surface seismiclocations and rose diagramshowing outcrop fractureorientations, maximumhorizontal stress directions from boreholeelongation and fractureorientations measuredfrom core, and the orientation of gilsonitedykes in outcrop. Theexact location for the seismic lines cannot beshown due to proprietaryconcerns.

waves and to produce a corridor stack for compressionwave, S1, and S2 for comparison with the surfaceseismic. The 9C VSP was acquired using both com-pression- and shear-wave vibrators with 3Creceivers magnetically clamped to the well at 16 mintervals over the target reservoir from depths of1800–2440 m. The compression data followed stan-dard VSP processing to produce a corridor stack forcomparison with the surface seismic data. Theshear-wave data were first deconvolved using theAlford rotation (Alford, 1986) to allow S1-S2 separa-tion. The separated S1 and S2 data were then indi-vidually processed and stacked in a manner similarto that of the compression data to give corridorstacks. Comparison of the S1 and S2 stacked datagave values of time difference between the fast andslow waves that indicated the degree of shear-wavesplitting. The time delays are shown in Figure 5.

The azimuth of the faster S1 orientation is shownin hodograms on Figure 5 for three depth intervalsin the well over a 60 ms time interval around themajor downgoing shear-wave event. All depths dis-played similar results to the three levels shown;however, these are not displayed due to spacerestrictions on the figure. A hodogram is a particlemotion diagram that shows the direction of firstmotion of the shear wave across the 3C receivers.The hodogram plots the arriving energy of onereceiver against another over a predetermined timeinterval around a major event, such as a reflectionor first arrival. Only hodograms are shown here forthe horizontal geophones rather than full 3-Dhodograms for clarity of interpretation. These plotsshow horizontal linear first motion, indicated bythe arrow on the figure, in a northwest-southeastdirection (N43W ±10°), thus indicating that thefirst arriving wave is polarized in this direction.That is, the polarization direction of the fast shearwave is in a northwest-southeast direction within afew wavelengths of the receivers at this location.

Analysis of the hodograms from all the 3C receiverlevels showed a consistent orientation of splitshear-wave data, indicating that the azimuth of fast

Bates et al. 1399

Table 2. Acquisition Parameters for 9C VSP* and Surface Seismic Survey

Receiver Recording Source Type SourceSpacing Parameters and Spacing Parameters

9C VSP* 3C** phones in Mertz M18,five stages at near and far15 m separation (167–342 m) offset

Surface 10 Hz 3C phones, 2 msec sample, Mertz, 16–96 HzShear Wave 12 per station, 6 sec record 91 m interval nonlinear sweep

46 m intervalSurface 10 Hz 3C phones, 2 msec sample, Mertz M18 10–64 HzCompression Wave 12 per station, 6 sec record vibrators, linear sweep

46 m interval 91 m interval

*9C VSP = Nine-component vertical seismic profile.**3C = Three component.

1-2%

Dep

th B

elow

KB

(m)

1000

0.026 0.030 0.034 0.038

2000Top of Upper Green River

Mahogony Bench

8%

5-12%

TN1

Anisotropy (%

)

Time Delay S1-S2 (msec)

x

y

x

y

x

y

Averagetime delay

Actual delay forindividual levels

N

N

N

Figure 5—Multicomponent vertical seismic profile (VSP).Time delays (points) between fast shear wave (S1) andslow shear wave (S2) shows shear-wave splitting of anaverage maximum value of 12% through the top of upperGreen River Formation. Hodograms (particle motion dia-grams) for three depth zones are shown in inserts withfirst motion to the northwest highlighted by the arrows.Depth below KB = depth below kelly bushing.

S1 direction did not change with depth from 868 to2637 m. From the uniform azimuth of fast S1 direc-tion, we postulate that the dominant open-fractureazimuth is also uniform over this depth rangearound the well.

The difference between arrival times of S1 andS2 indicates a variation in amount or degree of split-ting with depth. The top 868 m exhibit a 3% shear-wave splitting. Between 868 and 2011 m, back-ground values of splitting of 1% were recorded. At2011 m (the top of upper Green River), an intervalof anomalous birefringence is marked. This in-crease, to a maximum of 11% splitting, is consistentwith an interpretation of a high open-fracture den-sity region aligned at an azimuth of N43W throughthe upper Green River Formation.

CROSS SECTIONAL SYNTHETIC SEISMICMODELS

Before the influence of fractures is considered ascausing variations in the compression-wave surfaceseismic data, variations in the reflection data due tostratigraphy must be accounted for. For this pur-pose, we created compression-wave zero-offsetsynthetic seismogram models from the sonic logsof 17 wells projected along the seismic lines(Figure 4). Each synthetic model top was 107 mabove the top of the upper Green River to ensurethat a full seismic wavelength above the section ofinterest was used. The models were generated firstby creating sonic log cross sections (for line 1 seeFigure 6; for line 2 see Figure 7). These cross sec-tions were tied for unit tops and a smooth intervalvelocity model was interpolated between each log.The compression-wave reflection coefficients werecalculated from the sonic logs with a constant den-sity assumption (a recognized limitation in themodeling), and the models were converted to two-way traveltime and filtered to match the field data(Figure 6C). The compression-wave zero-offset synthet-ic models were then compared to the compression-wave migrated near-offset stack field data. Thesefield data, which contain only near-offset stackeddata, should be the most similar to that from themodel, which is only zero offsets and has no AVOeffects from the far offsets. From a comparison ofthe zero-offset synthetic models and near-offsetstack field data (Figure 6C, D), we concluded thatlateral stratigraphic changes are faithfully represent-ed by the reflections in the near-offset (0–1796 m)field stack data. That is, near-offset stack amplitudechanges on both lines showed first-order influenceof stratigraphy and lithology on the amplituderesponses that were predictable from the soniclogs and geological history of basin development;furthermore, because variations in lithology and

stratigraphy can account for the amplitudechanges, no influence of fracturing is manifest onthe near-offset stack data. This conclusion can bemade for both line 1, parallel to the open-fracturetrend, and line 2, perpendicular to the predictedopen-fracture trend.

SURFACE SEISMIC: SHEAR WAVE

In a similar manner to the VSP data, the surfaceseismic ref lection data were analyzed using theAlford rotation to separate the split shear wavesbefore separate processing of the fast and slowshear-wave data to yield S1 and S2 stacked sections.From the analysis of the S1 and S2 directions usingthe Alford rotation, an average azimuth of the fastshear wave at N30W was measured along both ofthe seismic lines. By comparing the traveltimes toreflectors in the S1 and S2 stacked sections, themagnitude of shear-wave splitting in the subsurfacewas calculated. An example of the shear-wavestacked sections is shown in Figure 8 where bothS1 and S2 sections are spliced together at well G, agas-producing well. With the S1 and S2 sectionstime-aligned at the top of the upper Green Rivermarker, an incremental shift with time (and depth)is seen between the two time sections such thatthe S1 section has the least traveltime (fastest veloc-ity) within each interval below. From this time shiftthe magnitude of traveltime splitting can be calcu-lated at 12% through the gas-producing intervalwithin the top of the upper Green River. Alongboth surface seismic lines a maximum shear-wavetraveltime splitting of 18% was recorded. Typically,shear-wave splitting of below 5% is regarded as abackground value (Crampin, 1994). The amplitudevariation between the S1 and S2 stacked sectionsmost likely is a function of lithology or heterogene-ity, but its analysis was beyond the scope of thisproject.

SURFACE SEISMIC: COMPRESSION WAVE

The near-offset stack data have been discussedand are interpreted as a reliable representation ofthe stratigraphic variations across the field. Torecord a manifestation of the fractures in thecompression-wave data, it is necessary to analyzethe far-offset data for amplitude variations with off-set (AVO). This is done at a location where there isinformation from more than one azimuth, paralleland perpendicular to the dominant fracture trend.It is assumed that changes in amplitude due tostratigraphy and lithology would give an equalresponse to ray paths from both azimuths, and thustheir affect can be accounted for. In this survey,

1400 Study of a Gas Reservoir

Bates et al. 1401

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1402 Study of a Gas Reservoir

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information from more than one azimuth is avail-able only at the tie point of the two lines. This limi-tation is quite common for reconnaissance data,but also demonstrates the utility of the technique ifa grid of 2-D compression-wave surface reflectiondata is available. The AVO gradient (change in AVO)or linear variation in reflectivity is proportional tothe change in Poisson’s ratio across a ref lectinginterface (Shuey, 1985). Because the effect of gas inthe pore space (or fracture space) (Nur, 1971) of arock is to decrease the Poisson’s ratio for the rock,AVO is an appropriate method for gas detection.

A comparison of AVO at the line tie is shown inFigure 9A for near-offset summed supergather andin Figure 9B for far-offset summed supergather. Asupergather is a sum of nine common depth-pointlocations on each line centered on the tie point. Atnear offsets (0–1796 m), a clear tie in time can bemade between the two lines, and for the majority ofreflectors a good comparison of amplitudes also canbe made; however, at far offsets (1796–2743 m)marked differences in amplitude are seen on the Zand Mahogony Bench marker horizons. For line 1,the amplitudes of these events are weak, as would

be expected for amplitudes dimming with offsetin either unfractured rock or rock where thereare no fractures filled with gas being crossed bythe compression-wave ray paths; however, on line2 there are large increases in amplitude, suggest-ing that the orientation of these ray paths crossesgas-filled fractures. The increase is counterintu-itive because of the reverse display polarity in thedata, but is consistent with models for open frac-tures provided by Crampin (1985), Thomsen(1988), and Allen and Peddy (1993). Note that the

Bates et al. 1403

Figure 8—Fast shear-wave (S1) stacked reflection sec-tion and slow shear-wave (S2) stacked reflection sectionspliced together at well G along line 1. Both sectionsthus are from northwest-southeast ray paths.

Figure 9—Compression-wave stacked sections alonglines 1 and 2 spliced at the well D, the line tie. (A) Com-parison of compression-wave near-offset (<1826 m) stackfor line 1 and line 2; (B) comparison of compression-wave far-offset (>1826 m) stack for line 1 and line 2.Note the amplitude differences between the far-offsetcomparison and the near-offset comparison.

amount of gas in the fractures cannot be deter-mined using this method because only a smallamount of gas will cause an anomaly (Domenico,1976; Ostrander, 1984).

Castagna and Smith (1994) suggested an alterna-tive display of AVO anomaly using the AVO gradientand AVO zero intercept. This display method hasthe advantage of suppressing variations in lithologyand porosity while remaining consistent to porefluid content variations and is shown for the tiepoint in Figure 10. Areas of anomalous amplitudesat the tie point on line 2 (interpreted as crossingthe dominant open gas-filled fractures) are shownwith hot colors (dominantly reds) at the Z markerhorizon and at the Mahogony Bench. Thus, thecompression-wave data can be said to show anamplitude variation with offset and azimuth(AVOA) at the tie point. The tie point is approxi-mately 1.2 km west of the gas discovery well at thisfield where a closed-in well blew with dramaticeffect in 1987. The horizon that was thought tohave caused the gas buildup was the Z interval. InFigure 10, the Z interval shows diminished amplitudes

(cool, blue colors) and is interpreted as a potentialdepleted zone on line 2 at the gas blow-out welllocation 1.2 km west of the line tie. Because line 1is oriented approximately parallel to the measuredopen-fracture direction, little influence on the AVOsignatures of the gas-filled fractures is seen on thisline

The preferred flow direction or maximum hori-zontal permeability direction of a reservoir usuallyis parallel to the dominant open-fracture direction.Heffer and Dowokpor (1990) attempted to relateseismic anisotropy not only to the local fracturing,but also to the amount of permeability anisotropythat exists in naturally fractured reservoirs.Unfortunately at the Bluebell-Altamont field, notwo wells were close enough to record interfer-ence effects between the wells, and no other infor-mation was available on flow anisotropy.

COMPARISON OF SHEAR-WAVE ANDCOMPRESSION-WAVE RESULTS

A comparison of the surface shear-wave splittingdata and surface compression-wave AVOA resultscan be made only at the line tie. The results forshear-wave traveltime splitting and compression-wave AVOA are plotted in Figure 11. A relationshipexists between the percent shear-wave traveltimesplitting and the AVOA anomalies. The highest AVOanomaly is observed at the Z-reflector (top of Z toTN1 interval), where an interval of high (12%)shear-wave traveltime splitting also begins. Theimplication from the compression-wave data is thatif data for both azimuths (parallel and perpendicu-lar to the dominant open and gas-filled fractures)existed at all points along the surface lines, similarresults could be anticipated. This approach sug-gests that the natural extension for this work is infull 3-D seismic surveys where every bin has anequal distribution of azimuths or has data for atleast two azimuths that are parallel and perpendicu-lar to the dominant fracture orientations. This rec-ommendation was made to the DOE and subse-quent continuation projects seek to investigate thepotential of 3-D seismic technologies. We postulatethat in 3-D surveys over fractured gas reservoirs,the data quality for compression-wave images ofstructure and stratigraphy would be higher whenthe ray paths are parallel to the open fractures and,furthermore, that if a gas chimney effect were pres-ent in the data, it would not be seen for these frac-ture parallel azimuths.

A further implication of the compression-waveresults is that if existing 2-D data are available atline tie points and if the orientation of the seismiclines are parallel and perpendicular to a majoropen-fracture trend, then there is the possibility of

1404 Study of a Gas Reservoir

Figure 10—Comparison of AVOA (amplitude variationwith offset and azimuth) at line tie (well D). Positive val-ues (hot colors) show AVO anomalies on line 2 acrossthe open gas-filled fractures. No anomalies are seen atthese depths on line 1 parallel to the fractures.

reevaluating old data for amplitude anomalies. Forsuch an evaluation, we recommend that the data bereprocessed to normalize parameters and proper-ties other than the fracture elements at the line tiewith careful attention paid to data quality.

CONCLUSIONS

The upper Green River Formation at the Bluebell-Altamont field, Utah, is a naturally fractured, butotherwise tight, gas sand reservoir. The naturalfractures show a preferential azimuth in field expo-sure (N30W and N65E) and well logs (N25W),with an indication from regional stress data thatthe open fractures are aligned in the northwest-southeast direction. The azimuth of open fractur-ing was coincident with that measured using sur-face and well shear-wave seismic. The surfaceshear-wave seismic mapped zones of high shear-wave splitting from which zones of increased natu-ral fracturing are inferred. The surface seismicresults were confirmed by results obtained from anine-component (9C) vertical seismic profile.

Compression-wave surface seismic results at the tiepoint of two lines indicated amplitude variationwith offset and azimuth anomalies that were con-sistent with an interpretation of an interval thatcontained open fractures parallel to the northwest-southeast line. The fracture content was most likelyto be gas; furthermore, the zones of high shear-wave traveltime splitting showed a relationship tothe compression-wave AVO and azimuth anomaliesrecorded at the top of the fractured intervals. Open,aligned, vertical fractures, which are at least par-tially gas saturated, are interpreted to be the causeof both the compression-wave and shear-wavevariations.

These seismic techniques are highly recom-mended for reconnaissance work over naturallyfractured reservoirs where new data are to beacquired. The techniques also are useful for reeval-uating older two-dimensional compression-wavedata where crossing lines or preferably a grid oflines is available; however, the full potential ofusing these seismic techniques to map and evaluatereservoirs with naturally fractured zones wherethere is likely enhanced production will be realizedonly in a three-dimensional (3-D) seismic surveywhere many subsurface locations have ray paths inmany orientations. Such 3-D surveys will requirefull-offset and full-azimuth data. The utility of thistechnique will extend beyond that for land reser-voirs to offshore marine reservoirs, in particularmarine reservoirs that may have had imaging prob-lems in the past because of naturally fractured gaschimneys when the gas cloud is primarily con-tained within vertically aligned fractures.

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anistropy; Dilley, Texas: Abstracts of papers presented at the 56thannual international SEG meeting, Houston, Texas, p. 476–479.

Allen, J. L., and C. P. Peddy, 1993, AVO frontiers, in Amplitudevariation with offset: Gulf Coast Case Studies, GeophysicalDevelopment Series, v. 4., p. 117–124.

Castagna, J. P., and S. W. Smith, 1994. Comparison of AVO indica-tors: a modeling study: Geophysics, v. 59, p. 1849–1855.

Crampin, S., 1994, The fracture criticality of crustal rocks:Geophysical Journal International, v. 118, p. 428–438.

Crampin, S., 1985, Evaluation of anisotropy by shear-wave split-ting: Geophysics, v. 50, p. 142–152.

Crampin, S., H. B. Lynn, and D. C. Booth, 1989, Shear-wave VSP’s:a powerful new tool for fracture and reservoir description:Journal of Petroleum Technology, v. 41, p. 283–288.

Domenico, S. N., 1976, Effect of brine-gas mixture on velocity in anunconsolidated sand reservoir: Geophysics, v. 41, p. 882–894.

Fouch, T., V. Nuccio, J. Osmond, L. MacMillan, W. Cashion, and C. Wandrey, 1992, Oil and gas in the uppermost Cretaceousand Tertiary rock, Uinta basin, UT, in T. D. Fouch, V. Nuccio,and T. C. Chidsey, eds., Hydrocarbon and mineral resources ofthe Uinta basin, UT and CO: Utah Geological AssociationGuidebook 2, p. 247–276.

Gries, R., 1983, North-south compression of Rocky Mountain fore-land structures, in J. D. Lowell, ed., Rocky Mountain foreland

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Figure 11—Comparison of compression-wave AVOA(amplitude variation with offset and azimuth) values atreflection interfaces and shear-wave traveltime splittingthrough formations at the tie point (well D).

AVO gradient difference (AVO gradient +intercept)/2

Z Marker

TN1

100.0

10.0

1.0

0.1

S-wave Splitting (%)D

epth

(m

)

100,000

10,000

1,000

100

10

P-wave AVOA

1500

2000

2500

Top of Upper Green River

Mahogony Bench

basins and uplifts: Denver, Colorado, Rocky MountainAssociation Geologists, p. 9–32.

Heffer, K. J., and A. B. Dowokpor, eds., 1990, Relationship betweenazimuths of flood anisotropy and local earth stresses in oilreservoirs, in A. T. Buller, E. Berg, O. Hjelmeland, J. Kleppe, O. Torsaeter, and J. O. Aaser, eds., North Sea oil and gas reser-voirs—II: The Norwegian Institute of Technology, London,Graham and Trotman, p. 251–260.

Johnson, R. C., 1985, Early Cenozoic history of the Uinta andPiceance Creek basins, Utah and Colorado, in R. N. Flores andS. S. Kaplan, eds., Cenozoic paleogeography of west-centralUnited States: Rocky Mountain Section, Society for EconomicPaleontologists and Mineralogists, p. 247–276.

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Thomsen, L. A., 1988, Reflection seismology over azimuthallyanisotropic media: Geophysics, v. 53, p. 304–313.

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Zobak, M. L., and M. D. Zobak, 1991, Tectonic stress field of thecontinental United States, in L. Pakiser and W. Mooney, eds.,Geophysical framework of the continental United States:Geological Society of America Memoir 172, p. 523–539.

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1406 Study of a Gas Reservoir

Richard Bates

Richard Bates received a B.Sc.degree in geology from the Uni-versity of Edinburgh in 1986 and hisdoctorate in geophysics from theUniversity of Wales in 1989. Hethen joined Blackhawk Geometricsas a geophysicist before becomingprogram manager for Departmentof Energy Contracts with a focus onmulticomponent seismic techniquesand hydrocarbon exploration.Currently, he is a lecturer in the sedimentary systemsresearch group, University of St. Andrews.

Heloise Lynn

Heloise Lynn holds a master’sdegree and doctorate in geophysicsfrom Stanford University. Sheworked for Texaco and Amocobefore forming Lynn Inc. in 1985.Lynn Inc. specializes in multicompo-nent seismic acquisition, processing,and interpretation. Heloise Lynn fre-quently teaches courses on fracturedetection using geophysical mea-surements and on anisotropy.

Michele Simon

Michele Simon graduated inphysics from the University ofHouston in 1980. She worked forGulf Oil for eight years and forMarathon Oil for 12 years beforejoining Lynn Inc. to work on multi-component seismic for 4 years.Currently she is a reservoir geo-physicist in the Permian basingroup at Amerada Hess Corporationin Houston, Texas.

Bates et al. 1407

ABOUT THE AUTHORS