James AlbrightLos Alamos National LaboratoryLos Alamos, New Mexico, USA

Bruce CassellDubai, United Arab Emirates

John DangerfieldPhillips PetroleumTananger, Norway

Jean-Pierre DeflandreInstitut Français du PétroleRueil-Malmaison, France

Svein JohnstadNorsk HydroBergen, Norway

Robert WithersARCO Exploration and Production TechnologyPlano, Texas, USA

Seismic Surveillance for MonitoringReservoir Changes

Time-lapse images and acoustic listening devices are the latest tools of the trade for tracking reservoir fluid

movement. These techniques, done with both active and passive seismic surveys, are presenting new ways

of getting more from the reservoir.

nSchematic seismic sections before and after production and their difference, attributable to moved fluid. The base survey (left), runbefore production, shows continuous amplitudes in the reservoir interval at 1.15 sec. The monitor survey (middle), run after production,shows a decrease in amplitudes in the reservoir interval only between shotpoints 110 and 120. Created by subtracting the base surveyfrom the monitor survey, the difference (right) accentuates the zone of fluid change.

90 100 110 120 130 140Shotpoint

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For years operators have developed sophis-ticated models of how fluid moves in reser-voirs. However, checking and calibratingthem against field measurements oftenmeets with limited success. Sample pointsmay be far apart or data hard to interpret.Now seismic surveillance offers high-qualitydata that might dramatically improve reser-voir management.

Seismic surveillance is a way to “watch”and “listen” to movement of reservoir fluids

4 Oilfield Review

far from the borehole. Knowing how fluiddistribution changes over time is importantfor more effective management decisions.For example, tracking fluid contacts duringproduction can confirm or invalidate flowmodels and thereby allow the producer tochange recovery schedules. Mappingsteamflood fronts during enhanced oilrecovery (EOR) can point to bypassed zonesthat may become targets of remedial opera-tions. Mapping hydraulic fractures revealsthe local stress field, which can govern per-meability anisotropy—vital input for wellplacement, stimulation treatment and waste

disposal. Seismic monitoring sheds light oneach of these problems by taking advantageof some traditional and some not-so-tradi-tional techniques.

The methods for watching and listeningto movement of reservoir fluids depend onthe rate at which the movement takesplace. For changes over months or years, asin the case of a moving gas-oil contact(GOC), the method of choice is time-lapse

nLaboratory results showing compressional wave velocity Vp (normalized) versus tem-perature and Vp versus gas saturation for sandstones. In oil-bearing sandstones (left) Vpdecreases with increasing temperature. (Adapted from Tosaya et al., reference 2.) Vp decreasesabout 40% (right) as gas saturation increases from 0 to a few percent. (Adapted from Murphyet al., reference 2.)

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seismic, sometimes called four-dimensional(4D), differential, or repeated, seismic.Images from traditional seismic surveystaken before and after production are com-pared, and the difference attributed tomoved fluids.

For changes taking place over microsec-onds to minutes—as when fractures areinduced or when fluid flows through natu-ral fractures—the technique is to use bore-hole sensors to localize the cracking noiseproduced by fluid movement. These sen-sors record signals from events similar totiny earthquakes, and much of the dataanalysis is borrowed from earthquake tech-nology. This article begins with a look atthe slow changes, then moves on to themore abrupt ones.

As reservoirs are exploited, pore fluidundergoes changes in temperature, pressureand composition. For example, enhancedrecovery processes such as steam injectionincrease temperature. Production of anyfluid typically lowers fluid pressure. Gasinjection and waterflooding mainly changereservoir composition. These fluid changesaffect the bulk density and seismic velocityof reservoir layers. Changes in velocity anddensity combine to affect the amplitude andtravel times of reflected waves. Most surfaceseismic monitoring is based on amplitudechanges rather than travel time. The key isto have amplitude changes big enough to beseen between the baseline survey and sub-sequent surveys (previous page).1

January 1994

For help in preparation of this article, thanks to EricBlondin, Gaz de France, Paris, France; Auguste Bossert,Elf Aquitaine, Pau, France; John Fairborn, ChevronPetroleum Technology Company, La Habra, California,USA; Roland Marschall, Geco-Prakla, Hannover, Ger-many; Bill Murphy and Brian Spies, Schlumberger-DollResearch, Ridgefield, Connecticut, USA; Scott Phillipsand Jim Rutledge, Nambe Geophysics, Incorporated, LosAlamos, New Mexico, USA; Lars Sonneland, Geco-Prakla, Stavanger, Norway.Dual-Burst Thermal Decay Time tool is a mark ofSchlumberger.

The expected change in seismic ampli-tude can be estimated from laboratory data.Most of the amplitude change comes fromfluid effects on rock velocity rather than onrock density. Laboratory experiments onfluid-filled rock show that the greatestchanges in velocity arise from two differentphenomena—introduction of gas into a liq-uid-filled rock or an increase in temperatureof a hydrocarbon-filled rock. Both cause adecrease in seismic velocity (above).2 Even

1. For a recent overview of the potential of seismic mon-itoring: Archer SH, King GA, Seymour RH and UdenRC: “Seismic Reservoir Monitoring—the Potential,”First Break 11 (September 1993): 391-397.

2. Murphy W, Reischer A and Hsu K: “Modulus Decom-position of Compressional and Shear Velocities inSand Bodies,” Geophysics 58 (February 1993): 227-239.Tosaya C, Nur A, Vo-Thanh D and Da Prat G: “Labo-ratory Seismic Methods for Remote Monitoring ofThermal EOR,” SPE Reservoir Engineering 2 (May1987): 235-242.Wang Z and Nur AM: “Wave Velocities in Hydrocar-bon-Saturated Rocks: Experimental Results,” Geo-physics 55 (June 1990): 723-733.

a small amount of gas decreases velocitydramatically by making the fluid compress-ible. At higher temperatures, hydrocarbonsbecome less viscous, reducing overall rigid-ity. Both effects are more prominent at lowpressures, such as in shallow, unconsoli-dated sands.

Monitoring EOR processes such assteamflooding and in-situ combustionusing 4D seismic was first performed in the1980s.3 The progression of temperature

5

3. For time-lapse 2D seismic, compared to poststeamcores: Britton MW, Martin WL, Leibrecht RJ and Har-mon RA: “The Street Ranch Pilot Test of Fracture-Assisted Steamflood Technology,” Journal ofPetroleum Technology 35 (March 1983): 511-522. Repeated 3D: Greaves RJ and Fulp TJ:“Three-Dimen-sional Seismic Monitoring of an Enhanced Oil Recov-ery Process,” Geophysics 52 (September 1987): 1175-1187.Monitoring using a single survey and permanent sen-sors: Pullin N, Matthews L and Hirsche K: “Tech-niques Applied to Obtain Very High Resolution 3DSeismic Imaging at an Athabasca Tar Sands ThermalPilot,” The Leading Edge 6 (December 1987): 10-15.

6

nProcessing stepsfor base survey andmonitor survey.Base and monitorsurvey steps areidentical except forrepositioning ofmonitor surveytraces. This stepcorrects for slightlydifferent subsurfacebounce points inthe monitor surveycaused by weatherand navigation differences.

Seismic Data Processing

Field data

Resample/trace sum

Amplitude recovery/mute

Designature

Dip moveout

Deconvolution

Velocity analysis

Normal moveoutcorrection

3D binned stack(bin width=75 m)

Dipcon

Deconvolution(1x50+100, sp. average)

Repositioning

Inline migration

Crossline interpolation(from 50- to 25-m lines)

Crossline migration

Whitening (with Q-based phase correction)

Well data matching

Filter/scale

Display

Monitor Survey

Field data

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Designature

Dip moveout

Deconvolution

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Normal moveoutcorrection

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Dipcon

Deconvolution(1x50+100, sp. average)

Grid regularization

Inline migration

Crossline interpolation(from 50- to 25-m lines)

Crossline migration

Whitening (with Q-based phase correction)

Well data matching

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Display

Base Survey

and gas fronts away from injection wellswas mapped using seismic amplitude dif-ference sections—a seismic section createdby subtracting the baseline survey imagefrom the monitor survey image. Corestaken after treatment provided independentverification on the extent of flooding—thesteam had caused additional hardeningand cementation.

These studies established the basic tech-nique used today. The baseline and subse-quent surveys must be acquired and pro-cessed in the same way. However, repeatinga survey with the same sources, receiversand positioning is nearly impossible. Addi-tional processing, therefore, is used to cor-rect for these and other undesirable differ-ences in the two surveys caused by weather,access or surface structures. To interpretamplitude differences in terms of fluidmovement requires a calibration, obtainedby matching reflection amplitudes outsidethe reservoir. Interpreting amplitude changesin terms of reservoir fluid changes is then avisual, qualitative step.

A more quantitative way of using 4Dseismic to monitor fluid movement is toinclude synthetic seismic sections andreservoir fluid flow simulations in the cali-bration and interpretation. Norsk Hydro isusing this technique to track a gas-oil con-tact during gas injection.4 Two 3D surveyswere acquired 16 months apart in the Ose-berg field, Norwegian North Sea (nextpage). Special care was taken to preservetrue amplitudes during processing (left ).The base survey served several purposes: itprovided structure for the initial reservoirmodel and input for further drilling anddevelopment decisions as well as acousticproperties of lithologies and fluids. Ampli-tudes of the base survey were used toderive acoustic impedances, using a pro-cess called inversion (see “Deriving Acous-tic Impedances Using Inversion,” nextpage ). Then acoustic impedances, theproduct of density and velocity, wererelated to rock types and fluid saturationsusing the reservoir fluid flow model derivedfrom production data.

Injecting gas into the Oseberg field pushesthe GOC deeper and farther from the injec-tion well. Dual-Burst Thermal Decay Time(TDT) measurements in a well bordering the

4. Johnstad SE, Uden RC and Dunlop KNB: “SeismicReservoir Monitoring over the Oseberg Field,” FirstBreak 11 (May 1993): 177-185.Johnstad SE and Ahmed H; “Reservoir Monitoring byApplication of the VSP Technique in the OsebergField,” presented at the 54th EAEG Annual TechnicalMeeting and Exhibition, Paris, France, June 1-5, 1992.

Oilfield Review

0 km 50

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Deriving Acoustic Impedances Using Inversion

January 1994

nLocation and structureof the Oseberg field, Norwegian North Sea.Area of seismic monitor-ing experiment isshaded pink and Well B-03 is marked green(below, left). Cross sectionshows the Oseberg for-mation dipping east. As gas is injected at thewell location, the gas-oilcontact moves eastward.

Inversion is so named because of its function as

the inverse of forward modeling. Forward model-

ing takes an earth model of layers with densities

and velocities, combines it with a basic seismic

pulse, and turns out a realistic seismic trace.

Inversion takes a real seismic trace, removes a

basic seismic pulse, and delivers an earth model.

The best inversions combine surface seismic,

borehole seismic, and sonic and density log data.

Seismic reflections are sensitive to acoustic

impedance contrasts, and not absolute impedance

magnitude. Borehole seismic and sonic data pro-

vide interval travel times at known depths, con-

straining the velocities of individual layers.

After these velocities are combined with densi-

ties, acoustic impedances are known for one well

location. A synthetic seismic trace is next com-

puted using the known acoustic impedance and a

basic seismic pulse. A filter is then derived that

matches the surface seismic data at the well with

the synthetic trace. The same filter is applied

everywhere to the surface seismic section, extrap-

olating the well-based information away from the

well using the surface seismic as a guide.

7

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nDual-Burst Thermal Decay Time logs showing thickening of a gas cap with time.The well location is at the southern edge of the monitored area. The Dual-BurstThermal Decay Time tool emits pulses of high-speed neutrons and measures therate at which thermal neutrons are captured. Gas is identified by an increase inthe count rate.

monitored area show the displacement ofthe GOC with time (left). This displacementagrees with that shown on surface seismicand with the simulated reservoir fluid flowfor the period between the seismic surveys(next page). Borehole seismic images fromthe field support the interpretation. Time-lapse vertical seismic profiles (VSPs) fromthe same well as the Dual-Burst logs alsoshow downward movement of the GOC(below). The sequence of seismic data inter-pretation, modeling and comparison withreservoir fluid flow models forms a loop, tak-ing advantage of feedback at many stages(page 10). Using these steps, Norsk Hydrogeophysicists have been able to validate theexisting reservoir model and develop amethodology for future monitoring.

Crosswell seismic images also lend them-selves to the time-lapse method.5 Unlike sur-face seismic surveys, which provide animage of reflector locations and acousticimpedance, or density times velocity, cross-well surveys directly map velocity betweenwells by measuring travel times. An examplefrom Chevron shows the velocity changesassociated with movement of a steam frontin the Athabasca tar sands of Alberta,

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May 5, ’90 June 6, ’90 Sept. 28, ’90 April 30, ’91 July 16, ’91 Nov. 6, ’91 July 16, ’92

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Oilfield Review8

nRepeated vertical seismic profiles. VSPs shot 22 months apart show the downwardprogression of the gas-oil contact, from 2.354 sec to 2.390 sec. With the known seis-mic velocity for the interval, this travel-time difference translates to a 44-m [145-ft]drop in the gas-oil contact—in agreement with TDT observations in the same well(above).

5. Justice JH, Mathisen ME, Vassiliou AA, Shiao I,Alameddine BR and Guinzy NJ: “Crosswell SeismicTomography in Improved Oil Recovery,” First Break11, no. 8 (June 1993): 229-239.Paulsson BNP, Smith ME, Tucker KE and Fairborn JW:“Characterization of a Steamed Oil Reservoir UsingCross-Well Seismology,” The Leading Edge 11, no. 7(July 1992): 24-32.

9January 1994

nOseberg seismicdifference sectionsand simulatedreservoir model sec-tions. At the left,from top to bottomare vertical sectionsof seismic line 60from the base sur-vey, the monitorsurvey and theirdifference. Thebrighter the color,the greater the difference. At theright, from top tobottom are simu-lated gas satura-tions at the time of base and moni-tor surveys of line 60, and theirdifference.

nHorizontal cuts through the middle of the reservoir. At the left is a time slice at 2356 msec of the seismic difference volume. Thegreatest difference appears around line 50, common depth point 700. The corresponding horizontal slice (right) through the simu-lated gas saturation difference volume predicts the same location for the greatest difference in gas saturation.

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Canada (next page, top). A base survey wasrun between two wells before steam wasinjected into a third well halfway between.The monitor survey, taken about threemonths after steam injection began, shows adecrease in velocity due to increased temper-ature near and above the perforated interval.

A monitoring technique that is justemerging is comparison of amplitude varia-tion with offset (AVO) in repeated surveys.AVO analysis has been shown to be a pow-erful fluid discriminator.6 Scientists at ElfAquitaine have made some progress in test-ing this technique for monitoring water-front movement in the Frigg field, Norway.7The Frigg has producing wells at the crestof the structure, but little other than seismicdata to describe the rest of the reservoir.Accurate estimates of gas reserves are cru-cial so that delivery contracts can be hon-ored. Two-dimensional seismic surveysconducted in 1973 and 1991 were analyzedaccounting for AVO and compared. Theinterpreted rise in the water front of about 50m [165 ft] is in qualitative agreement withproduction data. There is an uncertainty ofabout 15 m [50 ft] due to low resolution ofthe 1973 data.

Real-Time MonitoringReal-time monitoring is a different kind ofseismic surveillance that goes by threenames: microseismic monitoring, acousticemission monitoring, or passive seismics.Pressure jumps caused by fluid injection,depletion or temperature change are rapidlytransmitted to surrounding rocks, causingstress changes. Stresses are released bymovement at fractures or zones of weaknessthrough microseismic events—tiny earth-quakes. Typically, microseismic events havevery small magnitudes, from -6 to -2 on theRichter scale, a logarithmic measure ofenergy released in a seismic event. Mostmicroseismic events have a million timesless energy than the smallest earthquake thatcan be felt by a human at the Earth’s sur-face, which is +2 to +3. However, somereservoirs have a history of felt seismicityinduced by human intervention.8

The transient nature of pressure changesrequires a different approach to monitoring.Sensors are deployed in boreholes, adaptingtechnology first developed to monitor earth-quakes, then for fractures created byhydraulic stimulation of hot, dry crystallinerocks for extraction of geothermal energy.9 In

the case of hydraulic fracturing for wellborestimulation and waste injection, passive seis-mics can provide information about orienta-tion and now height and length of inducedfractures, depicting fracture containment.10

With orientation information, well locationscan be optimized to take advantage of per-meability anisotropy associated with frac-tures, and waste containment can be assuredfor regulatory purposes.

How does microseismic monitoringwork? Although the mechanism ofhydraulic fracturing is usually understoodto be tensile failure, many microseismicexperts believe that recorded events arecaused by shear failure along fractures.Energy radiates as a compressional (P) wavetraveling at the P-wave speed followed by ashear (S) wave traveling at the slower S-wave speed (next page, bottom). A conve-niently located triaxial borehole receiverrecords signals that may be analyzed tolocate the source of the emissions—some-times up to 1000 m [3300 ft] away.

Location is determined by distance anddirection from the receiver. Distance to theevent can be obtained by knowing thevelocities of P waves and S waves and the

10 Oilfield Review

Base seismic

Monitor seismic

Integrated Analysis

Seismic inversion

Refinedgeological model

Reservoir simulation

Base saturations

Base synthetics

Delta seismic

Delta saturations

Compare

Monitor synthetics

Monitor saturations

Delta synthetics

nFlowchart for integrated analysis.

6. Chiburis E, Franck C, Leaney S, McHugo S and Skid-more C: “Hydrocarbon Detection With AVO,” Oil-field Review 5, no. 1 (January 1993): 42-50.

7. Bossert A, Blanche J-P, Capelle P, Marrauld J andTorheim E: “Seismic Monitoring on the Frigg Gasfield(Norway) Using AVO Attributes and Inversion,” pre-sented at the 55th EAEG Meeting and Technical Exhi-bition, Stavanger, Norway, June 7-11, 1993.

8. For more on earthquakes caused by uncontrolledwastewater injection: Evans DM: “Man-Made Earth-quakes in Denver,” Geotimes 10, no. 9 (May-June1966): 11-18.For more on earthquakes caused by secondary recov-ery: Davis SD and Pennington WD: “Induced SeismicDeformation in the Cogdell Oil Field of West Texas,”Bulletin of the Seismological Society of America 79(October 1989): 1477-1494.Raleigh CB, Healy JH and Bredehoeft JD: “An Experi-ment in Earthquake Control at Rangely, Colorado,”Science 191 (March 26, 1976): 1230-1237.For more on earthquakes caused by production in theLacq Field, France: Segall P: “Earthquakes Triggeredby Fluid Extraction,” Geology 17 (October 1989):942-946.Feignier B and Grasso J-R: “Seismicity Induced by GasProduction: II. Lithology Correlated Events, InducedStresses and Deformation,” Pure and Applied Geo-physics 134, no. 3 (1990): 427-450.

9. Albright JN and Pearson CF: “Acoustic Emissions as aTool for Hydraulic Fracture Location: Experience atFenton Hill Hot Dry Rock Site,” SPE Journal 22(August 1982): 523-530.

10. The goal of fracturing is to create a contained frac-ture—a fracture only in the producing formation. Ifthe fracture propagates through bounding layers thatshould act as seals, fluids will leak.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaTime, msec

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nCrosswell images before and after steam injection in the Athabasca tar sands, Alberta,Canada. The base survey (left) was acquired before steam injection. The injection well ishalfway between the survey wells. The monitor survey (right) was run three months aftersteam injection began. The reservoir interval is 190 to 260 m, with a gas cap from 197 to205 m. Perforation interval is 240 to 250 m. As seen from the velocity decrease—moreorange and red—the steam has risen and taken off to the right. (Courtesy of John Fairborn,Chevron Petroleum Technology Company, La Habra, California, USA.)

nMicroseismic mon-itoring schematicshowing boreholeseismic tool down-hole, fracturingevents, and anacoustic emissionrecording of threecomponents show-ing P- and S-wavearrivals. Polarizationof the P-wave isalong the raypathconnecting theevent and receiver.Event locations (top)are from an exam-ple in Kentucky(next page).

11January 1994

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lag between their arrivals. Direction isknown from polarization or particle motionof the P wave, which is along the path con-necting the event and the receiver. Whenseveral borehole receivers can be deployedsimultaneously, event locations may also bedetermined by triangulation, knowing thevelocity of the P waves. Unlike activesources, however, the timing of a microseis-mic event cannot be controlled. Specialrecording systems listen for days, as forearthquake detection.

Most microseismic monitoring experi-ments are conducted in dedicated observa-tion wells near an injection well and awayfrom noisy pumps. However, in one experi-ment by Schlumberger in The Netherlands,fracturing events were recorded by a slim-hole accelerometer-based seismic tool thathad been clamped in an injection well.11

A hydraulic fracture monitoring experi-ment in the South Belridge field in Californiaused multiple geophones and hydrophonesin three vertical observation wells.12 Eventsfrom minifracs and the main fracs were scat-

tered around a plane indicating a verticallysegmented fracture 250 ft [76 m] long(below). The spread of events in the horizon-tal plane is interpreted by some to be indica-tion of a wide “process zone”—the volumeof earth disturbed by fracturing—surround-ing the main fracture.

Seismic monitoring can also be used toidentify the mechanisms of subsidence asfluids are extracted from a reservoir. The bestknown example is the Ekofisk field in theNorth Sea, where subsidence is affecting sur-face structures such as platforms andpipelines. The Ekofisk is a porous chalkwhich, when depleted of its fluid, is com-pacted by the overburden. Original subsi-dence models based on pore collapse ledPhillips Petroleum Norway to execute a plat-form relief program by jacking platforms up6 m [20 ft] to permit continued productionfor the life of the field. Downhole monitoringhas since shown that the Ekofisk exhibitsshear fracture microseismicity, possibly indi-cating that subsidence is caused by a combi-nation of pore collapse and shear sliding.

Subsidence surpassed early model estimatesbased on pore collapse, indicating othermechanisms at work. Studying the locationof the microseismic events may allow identi-fication of fault planes. The crestal part of thefield is obscured to normal surface seismicbecause of gas in the layers above the field,so this might represent a better method oflocating faults there.

A monitoring breakthrough has beenmade in mapping acoustic signals associatedwith oil production—no injection, no frac-turing, just primary production—in ClintonCounty, Kentucky, USA. Borehole receivershave been able to detect tiny acoustic sig-nals resulting from adjustments on naturalfractures as oil is produced. A map of eventsup to 1000 ft [330 m] from the sensors indi-cates a natural fracture network that is beingused to locate drilling targets in the Ordovi-cian carbonate formation (previous page,bottom). Acoustic emission monitoringcould be used to map fluid paths in the thou-sands of reservoirs that depend on naturalfractures for permeability.

11. Stewart L, Cassell BR and Bol GM: “Acoustic-Emis-sion Monitoring During Hydraulic Fracturing,” SPEFormation Evaluation 7 (June 1992): 139-144.

12. Vinegar HJ, Wills PB, DeMartini DC, ShlyapoberskyJ, Deeg WF, Adair RG, Woerpel JC, Fix JE and Sor-rells GG: “Active and Passive Seismic Imaging of aHydraulic Fracture in Diatomite,” paper SPE 22756,presented at the 66th SPE Annual Technical Confer-ence and Exhibition, Dallas, Texas, USA, October 6-9, 1991.

13. Kommedal JH, Berteussen K-A, Barkved OI, Jahren Land Rathore J: “Experience With Sea Bottom Acous-tic Sensors on the Valhall Field,” presented at the55th EAEG Meeting and Technical Exhibition, Sta-vanger, Norway, June 7-11, 1993.Kolbjørnsen K, Larsen DO, Kristiansen P andBerteussen KA: “Monitoring of an Underground Flowby Sea Bottom Seismic Instruments—A Case Study,”presented at the 53rd EAEG Meeting and TechnicalExhibition, Florence, Italy, May 26-30, 1991.

14. In a joint research project with Compagnie Générale

de Géophysique, ELF, Gaz de France and TOTAL:Deflandre J-P, Laurent J and Blondin E: “Use of Per-manent Geophones for Microseismic Suveying of aGas Storage Reservoir,” presented at the 55th EAEGMeeting and Technical Exhibition, Stavanger, Nor-way, June 7-11, 1993.

nFracture events in Belridge diatomite. Plan view (left) shows a cluster-ing of events along N25E, the interpreted strike of the fracture. The verti-cal section (middle) looking along the strike shows the scatter of eventsaround two planar segments. The view orthogonal to strike (right) showslength of fracture to be 300 ft [93 m]. (From Vinegar et al., reference 12, copy-right 1991 SPE.)

Oilfield Review

nTwo types of permanent geophones developed and tested by Institut Français du Pét-role. Sensors cemented behind casing (left) are strongly coupled to the formation, but oth-erwise inaccessible for modifications. Sensors on tubing (right) use springs to clamp tocasing, in a trade-off between coupling and mobility. (From Deflandre et al., reference 14.)

Permanent SensorsAll of these ideas are gaining momentumbut are costly because they use conven-tional equipment that must be deployedeach time a survey is made. Monitoringfluid production or injection might makemore commercial sense with permanentsensors. On or near the surface, permanentsensors could make for more accurate con-trol of repeated 3D surveys. In the borehole,permanently cemented receivers can pro-vide continuous data of higher quality thantemporarily clamped tools because of bettercontact with the formation.

Progress on permanent surface receivershas been shown by Amoco ProductionCompany in early time-lapse studies onland, where “surface” geophones werecemented at a depth of 10 m [33 ft]. Seabot-tom sensors have been tested in the NorthSea by Amoco Norway and by SAGAPetroleum.13 In addition to seismic energyfrom regular survey acquisition, these sen-sors have picked up microseismic signalsfrom the reservoir itself, and from nearbycuttings injection and drilling. Another ideaunder consideration is seabottom cable—astring of connected sensors that can lie onthe seabottom. Bottom cable is currentlyused for acquisition of surface seismic datain transition zones—swamps, lakes—and inother shallow water settings. It may haveapplications as a permanent sensor thereand in deeper waters.

On the downhole side, Institut Françaisdu Pétrole has tested two types of perma-nent borehole sensors—one behind casingand one around tubing (above, right). Theon-tubing sensors have been used to mapgas injection using both differential seismicand acoustic emission monitoring.14 Natural

January 1994

gas is injected into an aquifer for under-ground storage, and withdrawn during win-ter months. Until now, displacement of thegas-water contact had been monitored usingneutron logs in observation wells (below).Microseismic events recorded during injec-

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nDisplacement of the gas-water contact as gas is injected for underground storage inGermigny, France. The displacement interpreted from a separate time-lapse seismicstudy agrees with the volume of gas injected into the proposed geology. Well MC 7 isinstrumented with permanent sensors.

nCross sectionthrough Well MC 7showing geophonelocations (G1, G2,G3) and microseis-mic events. Eventsare indicated bydots and locatedrelative to the reser-voir interval. Allevents have beenprojected onto asingle cross section.The larger the dot,the greater themagnitude of theevent. (From Deflandreet al., reference 14.)

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaDepth, m -750

-775

-800

-825

-850

-875

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-9250 50 100 150 200

Reservoir

Distance, m

Well MC 7

G3

G2

G1

tion cluster at the top and bottom of gas-saturated layers (above). Differential seis-mic measurements agree with both logobservations and gas volumes injected andwithdrawn. So far, the permanent sensorshave been in continuous operation for overthree years.

In Bura, Texas, USA, ARCO is experi-menting with permanent sensors to monitorinjection of solid waste. ARCO scientistshave monitored a massive hydraulic fracturefrom two observation wells placed near awing of the predicted trajectory of theinduced fracture. Each observation well wasinstrumented with 25 triaxial geophonescemented between casing and tubing. Thepurpose of the test was to prove thatinjected slurries can be tracked for eventualwaste injection monitoring. Permanent

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downhole sensors of all types, includingpressure, temperature, acoustic, and per-haps resistivity (for fluid saturation) may bethe wave of the future.

The future of seismic surveillance is full ofpromise, but challenges remain for both 4Dand microseismic monitoring. Time-lapsemethods have benefited from advances inseismic acquisition and processing as 3Dseismic has become routine. But quantita-tive interpretation of 4D seismic images toidentify saturation changes will requireimproved collaboration of petrophysicists,reservoir engineers and geophysicists.

Microseismic monitoring needs toundergo some fine-tuning—especially instandardization of acquisition and process-ing—as the technology adapts to the oil andgas industry. Microseismic data interpreta-tion will benefit from further research onhow seismic events are generated bychanges in pressure and temperature. Thepotential is there to use seismic signals as apowerful diagnostic tool, to monitor thereservoir throughout its lifetime—from dis-covery through management of develop-ment and production. —LS

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