Pure appl. geophys. 153 (1998) 95–1110033–4553/98/010095–17 $ 1.50+0.20/0

Injection-induced Microseismicity in Colorado Shales

SHAHRIAR TALEBI,1 TOM J. BOONE2 and JOHN E. EASTWOOD3

Abstract—Imperial Oil Resources Limited uses cyclic steam stimulation to recover oil from theirCold Lake oil field in Alberta. This operation, in particular situations, can be associated with the failureof well casings in the Colorado shales above the oil-bearing formation. A number of fluid injectionoperations was undertaken at this site and the associated microseismicity was detected using twothree-component geophones and fifteen hydrophones. The purpose of this experiment was to simulatethe occurrence of a casing failure, determine the feasibility of monitoring in a shallow environment, andcharacterize the microseismic activity. A calibration survey provided values of 17869108 m/s forP-wave velocity, 643956 m/s for S-wave velocity and 0.42890.017 for Poisson’s ratio in the shaleformation. Estimates of the quality factor QP were 15 for the horizontal direction and 38 for the verticaldirection, corroborating the evidence of velocity anisotropy. Calibration shots were located to within 10m of the actual shot points using triangulation and polarization techniques. Several hundred microseis-mic events were recorded and 135 events were located. The results showed that microseismic activity wasconfined to depths within 10 meters of the injection depth. The experiment clearly established thefeasibility of detecting microseismicity induced by fluid injection rates typical of casing failures in shalesat distances over 100 m.

Key words: Water injection, microseismicity, source location, P- and S-wave velocity, attenuation,polarization.

Introduction

Injection of fluids under high pressure into a rock mass has several scientific andindustrial applications, including the measurement of regional stress fields and thedevelopment of deep exchangers in hot-dry-rock geothermal projects. In the oilindustry, fluid injections are mostly undertaken in order to increase the productivityof oil wells. Among different techniques investigated to detect fracture propagationduring fluid injection operations in rock masses, monitoring and analysis ofmicroseismic activity associated with fluid percolation has been proved to be the most

1 CANMET, 1079 Kelly Lake Rd., Sudbury, Ontario, Canada P3E 5P5. Fax: (705) 670-6556,E-mail: stalebi@nrcan.gc.ca

2 Imperial Oil Resources Ltd., 3535 Research Rd. NW, Calgary, Alberta, Canada T2L 2K8.3 Exxon Production Research Company, P.O. Box 2189, Houston, Texas, 77252, U.S.A.

Shahriar Talebi et al.96 Pure appl. geophys.,

reliable technique. This method has been in use over the last two decades ingeothermal applications (e.g., ALBRIGHT and PEARSON, 1980; PEARSON, 1981;CASH et al., 1983; NIITSUMA et al., 1985; MURPHY and FEHLER, 1986; TALEBI andCORNET, 1987; HOUSE, 1987) as well as oil and gas applications (e.g., POWER et al.,1976; THORNE and MORRIS, 1988; SARDA et al., 1988; TALEBI et al., 1991;DEFLANDRE and DUBESSET, 1992). Because of technical limitations and the cost ofthe application of this technique at large depths, many authors have been limited tothe use of only one borehole for sensor installation and sometimes even only onethree-component sensor. Determination of the geometry of hydraulic fracturesinduced by fluid injections has been the dominant objective of the application ofthis technique in the oil industry.

This paper summarizes the results of a pilot project, based on the use ofmicroseismic techniques in the Cold Lake oil field in Alberta. The extremely highviscosity of the bitumen in this oil sands deposit is the main obstacle for economicrecovery of heavy oil. The procedure used for oil extraction is Cyclic SteamStimulation (CSS) which consists of injecting large volumes of steam under highpressure and temperature (300°C) to reduce the viscosity of the bitumen and allowits flow towards producing wells. Steam injection is alternated with oil and waterproduction for as many cycles as economic conditions permit (KRY, 1989). The oil-bearing Clearwater formation, located 400–450 m below surface, is the target ofthese operations. In particular situations, this operation can cause failure of wellcasings in the 200–250 m depth-range in the Colorado shale formation, whichcauses concern from an operational and environmental point of view. The develop-ment of a reliable tool capable of early detection of casing failures is of utmostimportance to the operation of this oil field.

The pilot project was designed to simulate the occurrence of a casing failure inthe shale formation and to detect the associated microseismic activity. Waterinjection operations at different flow rates were undertaken at a depth of 220 m ina location remote from oil-producing wells. A calibration survey was performed inorder to measure the seismic properties of the shale formation. The main objectiveof this project was to determine if microseismic monitoring techniques couldconstitute an effective early-warning tool for detecting fluid flow caused by casingfailures. Other issues to be addressed by the project consisted of the comparison ofdifferent source location techniques, determination of maximum distances at whichmicroseismic events can be reliably detected and the design of an optimum sensorarray for a large-scale application of the technique.

Description of the Experiment

Figure 1 shows a plan view of the test site and the location of the injection welland the four observation wells. Two three-component geophones with dual-gain

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preamplifiers programmable from the surface were specially designed for thisexperiment and cemented in the borehole (G) at depths of 199 m (G1) and 249 m(G2). The three remaining observation wells (H1, H2 and H3) were used for theinstallation of strings of five hydrophones (depths of 180 m, 200 m, 220 m, 240 mand 260 m). The key issue in the design of the geometry of the array of sensors wasto provide suitable coverage of the area around the injection point, which wasexpected to generate microseismic activity. Signals from the two three-componentgeophone assemblies were amplified down hole at two different gains and passedthrough the conditioning and triggering boards of a data acquisition system, alongwith signals from the three hydrophone strings. The A/D boards acquired datawhenever user-defined criteria on triggering conditions were met. Calibration testsrevealed a flat frequency response of the entire system up to 1.5 kHz. The samplingrate was 7.5 kHz/channel and the anti-aliasing filters with a slope of 72 dB/octavewere set at 2 kHz.

Water injection operations took place in four stages during September andOctober 1995 (Table 1). The level of the aquifer was monitored throughout theexperiment using a borehole at a distance of about 120 m from the injection well.Since the nearest aquifer was located at depths of 100–120 m above the injectionpoint, it was expected that the injected water would have little effect on the aquiferlevel. The observations, however, showed that there was very rapid communicationwith the aquifer, as indicated by the strong correlation between the aquifer levelbelow surface and the total injected volume (see Fig. 2). Possible causes of thisoccurrence include fluid flow along a pre-existing vertical fracture or along the

Figure 1Plan view of the test site showing the location of the injection well and the boreholes used to install

three-component geophones (G) and string of five hydrophones (H1, H2 and H3).

Shahriar Talebi et al.98 Pure appl. geophys.,

Table 1

Summary of the four stages of injection operations

Duration Average rate Injected volumeStage Start date (hours:min.) (m3/hr) (m3)

1 Sept. 14, 1995 71:50 2.7 1912 Sept. 18, 1995 20:39 10.2 2083 Oct. 2, 1995 11:20 28.2 3204 Oct. 10, 1995 17:08 24.3 416

interfaces between the casing, cement and the rock mass. For the purposes of thepilot project, this observation simply means that only a fraction of the injectedfluids was entering the shales so that the flow rates and injected volumes reportedin Table 1 are upper bound values. Aquifer monitoring can be an alternativemethod of casing failure detection provided there is immediate communication toan aquifer that effectively behaves as a confined volume. In general, however,immediate communication to the aquifer is not the case for a typical casing failureand reliable interpretation of such data can be difficult due to a number of factorsincluding the size and permeability of the aquifer and the natural rise and fall of itslevel.

Figure 2Comparison between variations, as a function of time, of the aquifer level in meters below surface (solidline), and cumulative injected volume in m3 (broken line). Bold numbers indicate start times of the four

stages of injection operation.

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During stage 1 of injection operation the down-hole gain of geophones wasgradually increased to 84 dB and 104 dB on low-gain and high-gain sensorsrespectively, and the gains of hydrophones on surface reached 34 dB to 40 dB. Thetriggering parameters were set to detect any events barely emanating from thebackground noise. However, no significant microseismic activity was detectedduring stages 1 and 2 of the operation. Much higher flow rates were used in stages3 and 4 (Table 1). Low-frequency noise levels on geophone sensors increased andmicroseismic events first were recorded early in stage 3. This trend continued duringstage 4 as events of substantially higher quality were detected early in the operationand continued to be recorded throughout this stage.

Velocity and Attenuation Measurements

Sonic logs from three wells in the vicinity showed average values of 2017 m/sand 667 m/s for P- and S-wave velocities between 180 m and 250 m of depth. Theaverage Poisson’s ratio was 0.425, 0.439 and 0.446 for the three boreholes. Apartfrom providing a range for elastic properties for the shale, sonic logs exhibitedvariations of these properties as a function of depth and well location. In order tomeasure these parameters in the frequency range of monitoring, six primacord shotswere detonated in the injection well and one shot was fired in H3 between 180 mand 220 m of depth (Fig. 1). The exact time of shot detonation was recorded on-sitefor the first four shots performed prior to injection operations. P-wave arrivalswere very clear on all sensors and generally easy to pick due to high signal-to-noiseratios. The polarity of the first arrival of P waves was clearly compressional on allrecorded signals for all the shots (Fig. 3). S-wave arrivals, however, were difficultto pick particularly for hydrophone signals. The average results for these four shotscan be summarized as follows:

P-wave velocity: 17869108 m/s

S-wave velocity: 643956 m/s

Poisson’s ratio: 0.42890.017.

Shales are generally considered to be transversely anisotropic (e.g., JOHNSTON andTOKSOZ, 1980; THOMSEN, 1986; WHITE et al., 1982). The symmetry axis is usuallythe vertical axis and the elastic medium is characterized by five independentconstants. In this case, which is equivalent to the case of stratified media withhorizontal layering, S waves decouple into SH and SV components. The velocitymodel here is sometimes considered to be a spheroid; i.e., an ellipsoid with one axisparallel to the vertical direction and the two other axes of a similar size in thehorizontal plane. Figure 4 shows the projection of P-wave velocity results onhorizontal and vertical axes. A similar approach was not attempted for S waves

Shahriar Talebi et al.100 Pure appl. geophys.,

Figure 3Signals from the first calibration shot at 220 m of depth.

because of the insufficient number of measurements. The best-fit ellipse to theP-wave data indicates a velocity anisotropy of 10.4%, defined as (VPH−VPZ )/VPH

where VPH and VPZ are velocities in horizontal and vertical directions. The largevariation around the horizontal direction seems to indicate the predominance of theeffects of layering on the results.

Attenuation measurements were attempted, using the rise time method origi-nally proposed by GLADWIN and STACEY (1974) based on an empiricalrelationship:

t=t0+CT/Q, (1)

where t is the rise time of the recorded signal, t0 is the rise time of the source, Cis a constant, T is travel time and Q is the quality factor of the medium. Accordingto KJARTANSSON (1979), who provided a theoretical basis for the above relation-

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ship for impulsive sources, C can only be considered to be a constant when Q islarger than 20. The asymptotic values of this parameter are 0.485 and 0.298 fordisplacement and velocity signals, respectively. BLAIR and SPATHIS (1982) haveindicated that the above equation is strictly valid for impulsive sources (t0=0)however problems arise for realistic sources, as C becomes dependent on theproperties of the source. BLAIR (1982) points out the effect of the frequencyresponse of the system on the results and the difficulty of reliable measurements,especially within 10 m of an impulsive source. STEWART (1984) considered differenttypes of non-impulsive sources and showed that although the proportionality of risetime and attenuation is valid only for an impulsive source function, the maximumattenuation experienced by a seismic pulse in the source-sensor path can still beestimated using this method. Some authors have reported comparable results usingthe rise time method and the spectral ratio method (JANNSEN et al., 1985; BOURBIE

et al., 1986).Figure 5a shows a plot of the rise times versus travel times for P-wave signals

detected on the two geophones from the six shots in the injection well. The straightline corresponds to a quality factor of 32 obtained by MCDONAL et al. (1958) fromin situ measurements in Pierre shale, a formation that has comparable seismicproperties to the shale formation considered here. The straight line seems toprovide a lower bound to our data although the scatter indicates a possibledependence on the angle of incidence. We assume a value of 0.1 ms for t0 based onprevious experiments using the same type of source (TALEBI et al., 1991), and

Figure 4P-wave velocities projected on horizontal and vertical axes.

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Figure 5(a) Rise time versus travel time for P waves. The straight line shows the relationship expected forQP=32; (b) QP versus the sine of the take-off angle between the source-sensor rays and the horizontal

plane.

calculate the quality factor for each measurement point from equation (1). Figure5b illustrates the results as a function of the sine of the take-off angle betweensource-sensor rays and the horizontal plane. The scatter in the data has beenconsiderably reduced and the results strongly indicate the existence of attenuationanisotropy. The best-fit line indicates that Q varies from 15 in the horizontaldirection to 38 in the vertical direction. This latter value is comparable with thevalue of 32 obtained by MCDONAL et al. (1958) for the vertical direction inPierre shale. The results are also compatible with those of JOHNSTON and TOK-

SOZ (1980) for Colorado oil shales in the laboratory where QP was estimated tobe about 28 and 14 perpendicular and parallel to the bedding planes, respec-tively.

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Sensor Orientation

The seven calibration shots were used to estimate the orientation of differentcomponents of the two geophones. In the first step, the polarization angles of theP-wave signals were calculated; i.e., two rotation angles needed to put all theenergy along the X component of each geophone (e.g., MATSUMURA, 1981). Noassumptions were made about the plunge of the Z components which wereestimated independently as a check to the accuracy of the technique. Sensororientations were then calculated given the coordinates of shot and geophonelocations. Table 2 gives the estimated azimuth of the X components and plunge ofthe Z components of the two geophones. The plunges of the Z component ofgeophone 1 revealed discrepancies and were corrected assuming a layer with aslightly different velocity at the location of this sensor. The convention for rotationsis a left-handed system and angles are positive for clockwise rotations around thepositive Z (vertical) and Y axes of the sensors. If we consider the average values forshots 2–7, the orientation of Z components can be estimated to within 1° of thevertical direction. The accuracy should be better for azimuth determinationsbecause a smaller scatter is observed. Individual measurements, however, can be offby 91° for azimuth and 95° for plunge determinations. The overall resultsindicate that accurate sensor orientation can be made with cemented sensors, usingan adequate calibration survey. The lower accuracy in the determination of theplunge of Z components is compatible with the layered nature of the shales andprevious results on seismic anisotropy.

Locations of calibration shots were estimated by applying triangulation andpolarization methods. The triangulation method was based on a damped least-squares technique using P- and S-wave arrival times. The results are shown inFigure 6 using two different symbols for (tp) indicating that only P-wave arrivaltimes were used, and for (tp&ts) indicating that both P- and S-wave arrival timeswere used. Another method consisted of analyzing the polarization of the incidentP waves in order to determine the source-sensor direction and the time differencebetween P- and S-wave first arrivals used for calculating source-sensor distances.Shot locations could then be estimated independently from signals of the top

Table 2

Azimuth of the X components and plunge of the Z components of the two geophones

Depth X ZGeophone Shot(s) Borehole (m) (deg.) (deg.)

1 1 H3 220 137.1 3.81 2–7 Injection 180–220 132.590.6 −0.592.92 1 H3 220 171.1 −4.82 2–7 Injection 180–220 167.191.0 −0.993.8

Shahriar Talebi et al.104 Pure appl. geophys.,

Figure 6Plan view (a) and cross section along E–W (b) of source location results of calibration shots usingdifferent methods. Solid circles show sensor locations and open circles show a sphere of 10 m radius

centered on shot locations. The horizontal and vertical scales are identical.

geophone (G1) and the bottom geophone (G2) (see Fig. 6). The last method wasbased on using only the polarization direction of incident P waves on the twogeophones. The results of this method, indicated by (G1&G2) in Figure 6, wereobtained by calculating the point of intersection of the incident rays on the twogeophones. The lower accuracy of plunge compared to azimuth estimations,

Injection-induced Microseismicity in Shales 105Vol. 153, 1998

discussed in the previous paragraph, manifests itself in the horizontal plane ashypocenters from polarization methods tend to be aligned along source-sensordirections. The overall results showed that reasonable estimates within 910 m ofthe actual shot locations could be made in the central area utilizing most of thesemethods.

Microseismicity

Microseismic events were first detected shortly after the beginning of highflow-rate injection tests (stage 3). It took a few hours before these events werestrong enough to be locatable and about ten hours before a reasonable data set wascollected. At the end of the injection operations (stage 4) several hundred microseis-

Figure 7Signals of the largest microseismic event recorded on October 2, 1995.

Shahriar Talebi et al.106 Pure appl. geophys.,

mic events were recorded. Figure 7 illustrates signals from the largest recordedevent, showing very clear onsets of P and S waves. A few other events had clear Pand S arrivals on geophone and hydrophone sensors and could be located usingfirst arrival times. The accuracy of source location determinations for these eventswas estimated to be about 10 m by comparing the results of different methods. Forthe majority of the events, however, the signal-to-noise ratio on hydrophone signalswas too low to allow a clear estimation of P- and S-wave arrival times. A total of135 events had a sufficient signal-to-noise ratio on the geophone sensors and couldbe located using polarization methods. Because of the difficulty of the accuratepicking of S-waves onsets, particularly towards the end of the experiment, the mostreliable results were obtained using the orientation of the incident P-wave signalsalone. Figures 8, 9 and 10 show source location results for three time periods duringthe two high-flow rate injection operations (stages 3 and 4). With the exception ofone event, all the activity clusters within a few tens of meters around the injectionpoint. In the horizontal plane, the apparent progression along the line between theinjection hole and well G results from the uncertainty in plunge determinationsdiscussed in the previous section. In spite of this bias, one can detect a progressionin the extent of the seismic region as a function of time in the horizontal plane. Theactivity is confined to depths within 10 m of the injection point.

The present results show the feasibility of casing failure detection using micro-seismic techniques, but have several other implications for future applications.Firstly, the use of only one three-component sensor in such applications is not idealas one would often be confronted with the uncertainty in phase identification andthe fact that many events with unclear S arrivals would be impossible to locate.Geophone sensors cemented in place are the most reliable option as regards sensorselection and coupling. Since a large-scale application of this technique would belimited to the use of only one observation hole per site, our final design for futureapplications consists of five three-component geophone sensors cemented in aborehole in the central area of each producing oil pad. Although the majority of theevents were detected at distances less than 100 m, their signal/noise ratios indicatethat most of them would have been detectable at much larger distances. Theproposed design should allow the detection of microseismicity several hundredmeters away from the sensor locations. Since producing wells are several tens ofmeters apart from each other at the depth range 200–250 m, the lower accuracy inplunge estimates should not be a major hurdle, as clear identification of any leakingwell should be possible using azimuth estimates.

Conclusion

The calibration survey provided values of 17869108 m/s for P-wave velocity,643956 m/s for S-wave velocity and 0.42890.017 for Poisson’s ratio in the shale

Injection-induced Microseismicity in Shales 107Vol. 153, 1998

Figure 8Plan view (a) and cross section along E–W (b) of location of events recorded on October 2, 1995. The

horizontal and vertical scales are identical.

formation. Estimates of the quality factor QP were 15 for horizontal directionand 38 for vertical directions, corroborating the evidence of velocity anisotropy.The orientations of Z components of the two three-component sensors wereestimated to within 1° of the vertical direction. Individual measurements, how-ever, could be off by 91° for azimuth and 95° for plunge determinations. Theoverall results showed that accurate sensor orientation can be made with ce-mented sensors using an adequate calibration survey. Also, estimates of actual

Shahriar Talebi et al.108 Pure appl. geophys.,

shot locations to within 10 m can be made in the central area employing differentmethods.

The location of microseismic events showed that the activity originated from anarea close to the injection point, but remained confined to depths within 10 m ofthe injection depth. Although the majority of the events were detected at distancesless than 100 m, their signal/noise ratios indicated that most of them would havebeen detectable at considerably longer distances. The experiment clearly establishedthe feasibility of a large-scale application of microseismic technology as a detection

Figure 9Plan view (a) and cross section along E–W (b) of location of events recorded on October 10, 1995. The

horizontal and vertical scales are identical.

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Figure 10Plan view (a) and cross section along E–W (b) of location of events recorded on October 11, 1995. The

horizontal and vertical scales are identical.

tool for casing failures in oil sands. Since a large-scale application of this tech-nique would be limited to the use of only one observation hole per site, thedesign for future applications consists of five three-component geophone sensorscemented in a borehole in the central area of each producing oil pad. Such adesign should allow the detection of microseismicity several hundred meters dis-tant.

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Acknowledgments

The authors would like to thank Imperial Oil Limited, Resources Division, fortheir financial support of this project and their permission to publish the data. Thecollaboration of our colleagues in IOL (Rick Bailey, Karl Pustanyk, Darcy Ward)and CANMET (Doug Becker, Denis Lebel, Paul Rochon, Parviz Mottahed) wasinstrumental in the successful completion of this project. We are grateful to S. J.Gibowicz and A. McGarr for their careful reviews which enhanced the quality ofthis paper.

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(Received June 12, 1998, revised/accepted August 10, 1998)

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