Borehole Seismic Surveys: Beyond the Vertical Profile/media/Files/resources/oilfield_review/ors07/aut07/... · 20 Oilﬁeld Review Borehole Seismic Surveys: Beyond the Vertical Proﬁle

20 Oilfield Review

Borehole Seismic Surveys: Beyond theVertical Profile

John BlackburnConocoPhillips U.K., Ltd.Aberdeen, Scotland

John DanielsOklahoma City, Oklahoma, USA

Scott DingwallAberdeen, Scotland

Geoffrey Hampden-SmithShell Exploration & ProductionAberdeen, Scotland

Scott LeaneyJoël Le CalvezLes NuttHouston, Texas, USA

Henry MenkitiLondon, England

Adrian SanchezVillahermosa, Tabasco, Mexico

Marco SchinelliPetrobrasRio de Janeiro, Brazil

For help in preparation of this article, thanks to ReginaldBurl, Ed Ferguson and William Phebus, Belle Chasse,Louisiana, USA; Allan Campbell, Mike Craven, Rogelio Rufinoand Bill Underhill, Houston; John Edwards, Muscat, Oman;Alan Fournier, St John’s, Newfoundland, Canada; KevinGalliano, Larose, Louisiana; John Graves, Hess Corporation,Houston; Caroline Kinghorn, Dave Milne, Gary Rogers andThilo Scharf, Aberdeen; and Colin Wilson, Fuchinobe, Japan.seismicVISION, SlimXtreme, StimMAP, VSI (Versatile SeismicImager) and Xtreme are marks of Schlumberger.

Today’s borehole seismic methods create new opportunities for investigating

formations penetrated by a borehole. From well construction and 3D subsalt imaging

to stimulation monitoring and high-pressure, high-temperature acquisition, borehole

seismic surveys reduce operator risk and help improve recovery.

3. Arroyo JL, Breton P, Dijkerman H, Dingwall S, Guerra R,Hope R, Hornby B, Williams M, Jimenez RR, Lastennet T,Tulett J, Leaney S, Lim T, Menkiti H, Puech J-C,Tcherkashnev S, Burg TT and Verliac M: “Superior Seismic Data from the Borehole,” Oilfield Review 15,no. 1 (Spring 2003): 2–23.

1. Point sources are implosive or explosive sources, suchas dynamite or airguns. Sweep sources are vibroseistrucks or other vibrating sources.

2. Marine vibrating sources have been attempted: Fischer PA: “Seismic Source Offerings Provide Optionsfor Operators,” World Oil 227, no. 6 (June 2006),http://www.worldoil.com/magazine/MAGAZINE_DETAIL.asp?ART_ID=2913&MONTH_YEAR=Jun-2006 (accessed October 8, 2007).

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Borehole seismic surveys are now among the mostversatile of all downhole measurement techniquesused in the oil field. Historically, the main benefitderived from these surveys, also known as verticalseismic profiles (VSPs), has been to link time-based surface seismic images with depth-basedwell logs. However, today’s borehole seismicsurveys have expanded beyond a simple time-depth correlation. The wide spectrum of seismicenergy that is now recorded and the variousgeometries currently possible with boreholeseismic surveys combine to deliver results notpreviously available. From these data, E&Pcompanies derive important information aboutreservoir depth, extent and heterogeneity, as well

as fluid content, rock-mechanical properties, porepressure, enhanced oil-recovery progress, elasticanisotropy, induced-fracture geometry andnatural-fracture orientation and density.

Originally, VSPs consisted of receiversdeployed in a vertical borehole to record the mostbasic signals from a seismic source at the surface.The innovations delivered by modern VSPs havecome about by recording more information andexpanding survey geometries with improvedacquisition tools. This article describes the typesof waves that can be recorded in the borehole, andthe tools that record them. We then briefly catalogthe many types of surveys that can be acquired,along with the information they can provide. Wecontinue with case studies demonstratingadvances in borehole seismic surveys, including3D VSPs and VSPs acquired while drilling,optimizing hydraulic fractures, monitoring perfo ra tion operations, and VSP acquisition inhigh-pressure, high-temperature conditions.

Types of WavesThe main types of waves generated and recordedin borehole seismic surveys are body wavesemitted by point sources or frequency-sweepsources, and consist of compressional, or primary,

P-waves and shear, or secondary, S-waves.1 Thesewaves propagate from man-made sources nearthe surface to borehole receivers at depth. In thecase of marine VSPs, and where land VSPs deployairguns in a mud pit, typically only P-waves aregenerated. However, depending on the receivergeometry and formation properties, both P-wavesand S-waves may be recorded if S-waves havebeen generated by conversion from a reflecting P-wave (below left). For land VSPs with sourcescoupled directly to the earth, both P- and S-wavesare generated and may be recorded.2

The signals recorded by borehole receiversdepend on the incoming wave type, the surveygeometry and the type of receiver. Most moderndownhole hardware for recording VSPs consistsof clamped, calibrated three-component (3C)geophones, which are able to record all compo -nents of P- and S-wave motion, including SV- andSH-waves.

The Schlumberger borehole seismic tool, theVSI Versatile Seismic Imager, offers up to 40 three-component receivers, called shuttles, that can bespaced up to 150 ft [46 m] apart to form an array6,000 ft [1,830 m] long (below).3 The 40-shuttletool has been deployed several times for VSPacquisition in the Gulf of Mexico. The VSI tool

> Propagation and reflection of compressionaland shear waves. At normal incidence,compressional P-waves reflect and transmit onlyas P-waves. However, at incidence other thannormal, such as when the source is placed somedistance from the rig, an incident P-wave canreflect and transmit P-waves and shear S-waves(top). P-waves have particle motion along thedirection of propagation, and S-waves haveparticle motion orthogonal to the direction ofpropagation (bottom). SV-waves are polarized inthe vertical plane and SH-waves are polarized inthe horizontal plane. Incident SV- and SH-wavesare generated by shear-wave sources.

SP

PS

PIncident P-wave

Receiver

SV

SH

P

> VSI Versatile Seismic Imager. Each of the 40 VSI shuttles contains threeorthogonally oriented geophone accelerometers in an acoustically isolatedsensor package that can be clamped to the borehole wall.


can be run in open hole, cased hole or drillpipe,and is clamped into position to provide optimumcoupling. Options for conveyance include wire -line, downhole tractor or drillpipe.

An advantage that borehole seismic surveyshave over their surface seismic counterparts istheir capability to record direct signals in a low-noise environment. The direct signal travelsdownward to the receivers, and so is referred to asa downgoing signal. Waves that reflect at deeperinterfaces and then travel up to a boreholereceiver are recorded as upgoing signals (above).Upgoing signals contain reflection information,and are used to create seismic images of sub -surface reflectors. Both upgoing and downgoingsignals can contain multiples, or energy that hasreflected multiple times, which can interfere withthe desired signal. Signals without multiples arecalled primaries. Downgoing signals can be used todistinguish multiples from primary arrivals, and toenable more reliable processing of the surfaceseismic upgoing wavefield.

In conjunction with P- and S-waves, whichpropagate from a near-surface source to thereceiver, different types of source-generatednoise arise. Tube waves are formed when source-generated surface waves transfer energy to theborehole fluid. The resulting fluid-guided wavetravels down and up the borehole, forcing theborehole wall to flex radially. Receivers clampedto the borehole wall record tube-wave energy onhorizontal geophone components. Tube waves

are sensitive to changes in borehole dimension,which can cause them to reflect. Another form ofnoise that sometimes contaminates recordings iscasing ringing.

The majority of VSPs use compressional andshear waves from airguns, vibrating trucks ordynamite sources for imaging reflectors, butenergy from other sources can be recorded andprocessed to yield information about the sub -surface. For example, the drill bit can act as adownhole source, generating vibrations that aredetected by sensors deployed at surface or onmarine cables.4 These recordings require special -ized processing, but can provide critical answersin time for decisions to be made while drilling,such as changing mud weight or setting casing.

Hydraulically induced fractures emit energyin much the same way as natural earthquakes,and these microseisms can be recorded bysensors in neighboring boreholes. Similarly,production of fluids or injection of fluids forenhanced recovery or waste disposal all inducestress redistribution that in turn can causedetectable microseismicity. And finally, boreholesensors can be used to record natural seismicity.5

Types of SurveysBorehole seismic surveys are usually categorizedby survey geometry, which is determined bysource offset, borehole trajectory and receiver-array depth. The survey geometry determines thedip range of interfaces and the subsurfacevolume that can be imaged.

The simplest type of borehole seismic surveyis the zero-offset VSP. The basic zero-offset VSPfeatures a borehole seismic receiver array and anear-borehole seismic source (next page, top). Inmost cases (unless formation dips are very high),this survey acquires reflections from a narrowwindow around the borehole. The standardoutput from a zero-offset VSP is a corridor stack,created by summing the VSP signals thatimmediately follow the first arrivals into a singleseismic trace. That trace is duplicated severaltimes for clarity and comparison with surfaceseismic images. Processing yields velocities offormations at different depths, which can be tiedto well log properties and interpreted fordetection and prediction of overpressured zones.The velocity model can also be used to generatesynthetics to identify multiples in surfaceseismic processing.

Another type of zero-offset VSP is known as adeviated-well, walkabove, or vertical-incidenceVSP. It is designed to ensure that the source isalways directly above receivers deployed in adeviated or horizontal wellbore. This surveyacquires a 2D image of the region below theborehole. In addition to formation velocities andan image for correlation with surface seismicdata, benefits of a walkabove VSP are goodlateral coverage and fault and dip identificationbeneath the well.

Offset VSPs are acquired using a sourceplaced at a horizontal distance, or offset, fromthe wellbore, again producing a 2D image. Thereceiver arrays are deployed at a wide range ofdepths in the borehole. The offset increases thevolume of subsurface imaged and maps reflectorsat a distance from the borehole that is related tothe offset and subsurface velocities. The addedvolume of illumination enhances the usefulnessof the image for correlation with surface seismicimages, and for identification of faulting and diplaterally away from the borehole. In addition,because the conversion of P-waves to S-wavesincreases with offset, an offset VSP allows shear-wave, amplitude variation with offset (AVO) andanisotropy analysis. The degree to which P-wavesconvert to S-waves depends on offset and oninterface rock properties.

Walkaway VSPs are similar to offset VSPs inthat the source is offset from vertical incidence,but the acquisition geometry is somewhatreversed. The borehole receiver array remainsstationary while the source moves away from it,or “walks away” at a range of offsets. The range ofoffsets acquired in a walkaway VSP is particularlyuseful for studying shear-wave, AVO and

22 Oilfield Review

> Upgoing, downgoing, primary and multiple arrivals. Upgoing wavesreflect at interfaces below the receiver and then travel upward to berecorded (blue and green). Downgoing waves arrive at the receivers fromabove (red and orange). A wave that arrives at the receiver withoutreflecting is called the direct arrival (red). Waves that reflect only once arecalled primaries. The reflected upgoing primary (blue) is the arrival that isdesired for imaging reflections.

Time

Dept

h

1

2

3

4

5

• Downgoing direct arrival• Reflected upgoing primary• Downgoing multiple• Reflected upgoing multiple


Autumn 2007 23

anisotropy effects. And, because they canilluminate a large volume of subsurface, offsetand walkaway VSPs are useful elements in thedesign of surface seismic surveys.

The surveys described so far are all designedto provide information and images in one or twodimensions. To adequately illuminate 3D struc -tures requires 3D acquisition and processing. Inthe same way that surface seismic surveys haveprogressed from 1D and 2D to 3D, so have VSPs.

Three-dimensional VSPs can be acquired onland or offshore. Acquisition of 3D marine VSPsis similar to that of 3D marine surface seismicsurveys and can follow parallel lines orconcentric circles around a borehole (right). Onland, source positions typically are laid out in agrid. Three-dimensional VSPs deliver high-resolution subsurface imaging for explorationand development applications, and requiredetailed prejob modeling and planning. Inaddition to producing images at higherresolution than surface seismic methods, 3DVSPs can fill in areas that cannot be imaged bysurface seismic surveys because of interferingsurface infrastructure or difficult subsurfaceconditions, such as shallow gas, which disruptspropagation of P-waves.

4. Breton P, Crepin S, Perrin J-C, Esmersoy C, Hawthorn A,Meehan R, Underhill W, Frignet B, Haldorsen J, Harrold Tand Raikes S: “Well-Positioned Seismic Measurements,”Oilfield Review 14, no. 1 (Spring 2002): 32–45.

5. Coates R, Haldorsen JBU, Miller D, Malin P, Shalev E,Taylor ST, Stolte C and Verliac M: “Oilfield Technologiesfor Earthquake Science,” Oilfield Review 18, no. 2 (Summer 2006): 24–33.

> Variations on a theme of VSPs (left to right). The original acquisition geometry, with no offset between source and wellbore, creates a zero-offset VSP.Seismic waves travel essentially vertically down to a reflector and up to the receiver array. Another normal-incidence, or vertical-incidence, VSP isacquired in deviated wells with the source always vertically above each receiver shuttle. This is known as a deviated-well, or walkabove VSP. In an offsetVSP, an array of seismic receivers is clamped in the borehole and a seismic source is placed some distance away. The nonvertical incidence can give riseto P- to S-wave conversion. In walkaway VSPs, a seismic source is activated at numerous positions in a line on the surface. All these survey types may beacquired onshore or offshore.

Offset VSP

Receivers

Source

Deviated-Well VSP

Receivers

Sources

Walkaway VSP

Sources Receiver

Zero-Offset VSP

Source

Receivers

> Three-dimensional VSPs. Onshore and offshore, 3D VSPs tend to borrow surface seismicacquisition geometries. On land, source positions usually follow lines in a grid. Offshore, sourcepositions can be laid out in lines or in a spiral centered near the well (left). Ray-trace modeling prior toacquisition ensures proper coverage and illumination of the target. In this offshore example (right),source lines at the surface are shown in red. Green lines are rays traced from source to receiver.Wells are positioned at the light blue triangles at the surface. Blue surfaces are the top and bottom ofa salt body. The target horizon is the red surface at the bottom.

Receiver

3D VSP


VSPs have long been used to tie time-basedsurface seismic images to depth-based well logs.In many exploration areas, the nearest wells maybe quite distant, so VSPs are not available forcalibration before drilling begins on a new well.Without accurate time-depth correlation, depthestimates derived from surface seismic imagesmay contain large uncertainties, adding risk andthe cost of contingency planning to drillingprograms. One way to develop a time-depthcorrelation is to perform an intermediate VSP: torun a wireline VSP before reaching total depth(TD). These surveys provide reliable time-depthconversions, but add cost and inefficiency to thedrilling operation, and may come too late toforecast drilling trouble.

To help reduce uncertainty in time-depthcorrelation without having to stop the drillingprocess, geophysicists devised a seismic-while-drilling process (above left). This technology usesa conventional seismic source at the surface, anLWD tool containing seismic sensors in thedrillstring, and a high-speed mud-pulse telemetrysystem to transmit information to the surface.6

Availability of real-time seismic waveforms allowsoperators to look thousands of feet ahead of thebit to safely guide the well to TD. Because drillinggenerates noise that could jeopardize seismic

data quality, source activation and signalmeasurement must take place during quietperiods, when drilling has paused for otherreasons, such as making drillpipe connections. Alimitation of this method is that the seismic LWDreceivers, being part of the drillstring, are notclamped to the borehole wall, althoughformation-receiver coupling generally improveswith well deviation.

Several borehole seismic technologies areavailable for understanding fractures andfracture systems, both natural and hydraulicallyinduced. The walkaround VSP is designed to

characterize the direction and magnitude ofanisotropy that arises from aligned naturalfractures. In this survey, offset source locationsspan a large circular arc to probe the formationfrom a wide range of azimuths (above).7

Hydraulically induced fractures can also bemonitored using borehole seismic methods. Whilethe fracture is being created in the treatmentwell, a multicomponent receiver array in amonitor well records the microseismic activitygenerated by the fracturing process (below).Locating hydraulically induced microseismicevents requires an accurate velocity model.

24 Oilfield Review

6. Breton et al, reference 4.7. Horne S, Thompson C, Moran R, Walsh J, Hyde J and

Liu E: “Planning, Acquiring and Processing a WalkaroundVSP for Fracture Induced Anisotropy,” presented at the64th EAGE Conference and Exhibition, Florence, Italy, May 27–30, 2002.

8. The fluid injection under discussion here is for pressuresupport, not for hydraulic fracturing.

9. Hornby BE, Yu J, Sharp JA, Ray A, Quist Y and Regone C:“VSP: Beyond Time-to-Depth,” The Leading Edge 25,no. 4 (April 2006): 446–448, 450–452.

10. Leaney WS and Hornby BE: “Subsalt Elastic Velocity Prediction with a Look-Ahead AVA Walkaway,” paperOTC 17857, presented at the Offshore Technology Conference, Houston, May 1–4, 2006.

> A VSP while drilling. The seismicVISIONseismic-while-drilling tool positioned near thedrill bit receives signals generated by a seismicsource at the surface. Signals are transmitted tothe surface for real-time, time-depth information.

VSP While Drilling

Receiver > A walkaround VSP. With the offset source at several azimuths, this surveycan detect anisotropy caused by aligned natural fractures.

> Microseismic method of hydraulic fracture monitoring. Sensitivemulticomponent sensors in a monitoring borehole record microseismicevents, or acoustic emissions, caused by hydraulic fracturing. Dataprocessing determines event location, and visualization allows engineers to monitor the progress of stimulation operations.

Reservoir

Microseism

Hydraulic fracture

Treatment well Monitoring well


Autumn 2007 25

Mapping the extent of the fracture with time helpsmonitor the progress of stimulation treatmentsand allows comparison between actual andplanned fractures. Real-time information aboutfracture extent and orientation promises to helpstimulation engineers optimize treatments byallowing them to modify pumping rates andvolumes when observed fractures differ from plan.A drawback of the method is that nearly allapplications have required deploying the receiverarray in a monitoring well because it is believedthat the treatment well is too noisy. The cost ofdrilling a monitoring well could be saved if thetechnology could be applied in treatment wells.

Another borehole seismic technology, calledpassive seismic monitoring, characterizes frac -tures by recording microseismic signals generatedwhen fluid is produced from or injected into anaturally fractured reservoir. When fluid injectionand production modify the stress state enough tocause seismic events, the resulting acousticemissions can be recorded in nearby monitoringwells by arrays of multicomponent boreholereceivers.8 The technique is similar to monitoringhydraulic fractures, but the events are smaller inmagnitude. The microseismic events can beplotted in space and time to identify the fracturesthat are responding to the change in stress state.Because the timing of microseismic events cannotbe predicted, acquisition systems for passive

seismic monitoring must be different fromstandard VSP acquisition systems. Recordingsystems need to be active for long periods of time,waiting to be triggered by acoustic emissions. Insome cases, receiver arrays are installedpermanently to record for extended periods.

Propagating seismic signals between wellscreates yet another type of borehole seismicprofile, known as a crosswell seismic survey(left). In these surveys, downhole seismicsources, such as downhole vibrators, aredeployed at selected depths in one borehole,shooting to a receiver array in another borehole.Because the direction from source to receiver issubparallel to layer boundaries, most raypathspropagate without reflecting. Recorded data areprocessed to extract information about thevelocities in the interwell region. Since crosswelldata do not contain much information aboutreflectors, layer boundaries in the initial velocitymodel used to process the crosswell datatypically come from sonic logs or standard VSPs.A limitation of the crosswell method is the maxi -mum allowable distance between boreholes—afew thousand feet is typical—which varies withrock type, attenuation, and source strength andfrequency content.

Many of the borehole seismic surveysmentioned above can be acquired at differentstages in the life of a reservoir. Offset VSPs,walkaways, 3D VSPs and crosswell surveys canalso be acquired in time-lapse fashion, beforeand after production. Time-lapse surveys canreveal changes in the position of fluid contacts,changes in fluid content, and other variations,such as pore pressure, stress and temperature.As with time-lapse surface seismic surveys, caremust be taken to repeat acquisition conditionsand processing as closely as possible so thatdifferences between baseline and monitoringsurveys may be interpreted as changes inreservoir properties.

The VSP method has evolved from its humblebeginnings as a time-depth tie for surface seismicdata to encompass a wide range of solutions toexploration and production problems.9 Theremainder of this article is devoted to casestudies that highlight the versatility of today’sborehole seismic surveys, starting with VSPsacquired while drilling.

Reducing Uncertainty in Well ConstructionBorehole seismic surveys are best known fortheir ability to tie time-based seismic sections todepth-based information such as well logs anddrilling depths. These correlations are possiblebecause the depth of each borehole seismic

sensor is known, and the time it takes for aseismic wave to arrive at the sensor is known.However, these correlations contain uncertain -ties when the well has yet to attain the depthsthat need to be correlated. In such situations, itis necessary to look ahead of the well’s TD andpredict formation properties ahead of the bit.

Two types of borehole seismic surveys—seismic-while-drilling imaging and intermediateVSPs—can provide look-ahead information. Inan example of the first, Devon Energy obtained aVSP image, in addition to time-depth and velocityinformation, while drilling a directional well inthe Gulf of Mexico. Waveforms acquired duringdrillpipe connection and transmitted to surfaceduring drilling operations were processed at aSchlumberger processing center and reported toDevon engineers at the rig site and in remoteoffices. An initial seismicVISION seismic-while-drilling image acquired 1,000 ft [305 m] abovethe target indicated that the well would notreach the target as planned (below). Devon teammembers in Houston decided to sidetrack thewell and used additional seismicVISION data toguide the well to the intended TD.

Intermediate VSPs also deliver informationbeyond TD. BP ran such a “look-ahead” walkawayVSP in a deepwater well in the Gulf of Mexico.10

> Crosswell seismic surveys, with sources inone borehole and receivers in another. Becauseraypaths are at large angles to any formationinterfaces, little energy is reflected; most energyrecorded by the receivers comes from directarrivals. These data reveal information aboutformation velocities in the interwell volume. Therepeatable survey geometry makes crosswellseismic surveys useful for time-lapse monitoringof steam injection, for example.

Sources

Receivers

Crosswell VSP

> Imaging while drilling. Two seismic imagesacquired while drilling (red and blue) aresuperimposed on preexisting surface seismicdata (black and white). The first seismic image(left of vertical black line), acquired in the originalwell (green) indicated to Devon interpreters thatthe well would not reach the target as planned.The well was sidetracked (yellow), and anotherseismic image acquired while drilling (right ofvertical black line) indicated that the well wouldreach the target.

Image acquiredfrom original well

Image acquiredfrom sidetrack

Original well

Sidetrack


The well was to penetrate a salt structure to tapsubsalt sediments. Drilling deepwater wellsthrough salt is expensive and risky. The saltobscures seismic signals from underlyingformations, making it difficult to image themproperly, and also forms such a strong seal thatpore pressure below salt can be abnormally high.

Estimates of pore pressure can be made fromthe ratio of seismic velocities derived fromprocessing surface seismic data, but these

velocities often have large uncertainties.11

Borehole seismic surveys can help reduce the riskof drilling into subsalt sediments by obtainingmore accurate seismic velocity ratios before thewellbore exits the salt.

In the BP survey, a 12-level borehole seismictool acquired walkaway data while clamped in thesalt near the base salt interface (above). In thiswalkaway configuration, 800 surface shots werefired in a line extending approximately 25,000 ft[7,600 m] on both sides of the well. Compressionalwaves generated by the source reflect back asboth P-waves, called P-p arrivals, and as S-waves,called P-s arrivals. With the tool clamped as closeas possible to the base of salt, the seismic energyreflecting at varying angles near the base of thesalt can be analyzed for amplitude variation withangle (AVA) of incidence. Analysis of AVA—analogous to well-known amplitude variation withoffset (AVO)—reveals elastic properties of thematerials at the reflecting interface.12

In this case, geophysicists expected tomeasure P- and S-wave velocities of the subsaltlayers, along with quantified uncertainties, to beused in estimates of pore pressure and safe mudweight.13 If results of the survey were to be usefulfor salt-exit drilling, time from last shot to mud-weight prediction had to be short, within two days.

Amplitude variation with angle depends on thedensity and compressional and shear velocities ofthe material on either side of the reflecting

interface. Measured AVA properties for P-p and P-s arrivals were compared with modeled values,and the inversion process iteratively modified themodel to achieve a best fit with the data (belowleft). Inverting for subsalt compressional andshear velocities is possible because the densityand velocities within the salt are known with ahigh degree of certainty. Noise in the data makesit difficult to invert for subsalt density, so anexpected value is assumed.

The inversion predicted the ratio of P- and S-wave velocities with lower uncertainties thanpredrill estimates. A dipole sonic log recordedbelow and through the salt provided a post-drillmeasure of subsalt velocities, which were withinthe uncertainties predicted by the look-aheadwalkaway VSP (below).

Double-Well 3D VSPIn the Riacho de Barra field, a mature asset inthe Recôncavo basin of northeast Brazil,Petrobras sought to reduce risks in an infill-drilling campaign. Conventional 3D surfaceseismic data over the field had not satisfactorilyresolved structural and stratigraphic traps: ahigh-velocity conglomerate formation in theoverburden attenuated seismic signals andreduced bandwidth, deteriorating resolution andmaking it difficult for interpreters to definereservoir boundaries (next page, top).14

To improve the seismic image, geophysicistsexamined the feasibility of conducting a 3D VSPin existing wells. The main goal of the survey wasto resolve erosional truncations of the upperreservoir and delineate a deeper target that had

26 Oilfield Review

> Acquisition of an amplitude variation with angle (AVA) walkaway VSP atthe salt base. Processing assumes that the raypaths through the salt areequivalent for the direct ray and the ray that reflects off the base of the salt.

Salt

> Comparison of AVA data and modeled results.P-p (red) and P-s (green) reflected amplitudescan be corrected with a 6° shift in the angle ofthe interface, corresponding to the dip of the saltbase (blue for corrected P-p, black for correctedP-s.) The best-fit model curves are shown inpurple for P-p and orange for P-s. (Modified fromLeaney and Hornby, reference 10.)

Refle

ctio

n co

effic

ient

–0.25

0

0.25

0.50

–0.50

–75 –50 –25 0 25 50 75Incidence angle, °

> Comparing predictions of compressional (Vp)and shear (Vs) velocities and uncertainty rangeswith measured values. The look-ahead walkawayVSP prediction of Vp and its uncertainty range(green) span the values later obtained by loggingin the same well (black). Similarly, the predictedVs and its uncertainty range (blue cloud)accurately estimated the subsequently loggedshear velocities (red curve). Also shown is thepredicted Vp /Vs ratio (red cloud) and the ratio oflogging results (blue curve). (Modified fromLeaney and Hornby, reference 10.)

Monte Carlopredictions

Vs Vp Vp/Vs

Dept

h

Velocity Vp/Vs ratio


Autumn 2007 27

been poorly defined by surface seismic imaging.An initial velocity model was constructed fromthe 3D surface seismic data and calibrated by logdata from more than 30 wells in the area. Ray-tracing through the model helped select thesurvey design that would maximize coverage atthe targeted interfaces.

The 3D VSP design comprised 2,700 shotpoints over a 13-km2 [5-mi2] area, to be recordedfrom two neighboring wells simultaneously(right). To optimize acquisition logistics, aPetrobras seismic crew performed essentialsurvey operations, such as location of shot points

11. Bryant I, Malinverno A, Prange M, Gonfalini M, Moffat J,Swager D, Theys P and Verga F: “Understanding Uncertainty,” Oilfield Review 14, no. 3 (Autumn 2002): 2–15.

12. Leaney WS, Hornby BE, Campbell A, Viceer S, Albertin Mand Malinverno A: “Sub-Salt Velocity Prediction with aLook-Ahead AVO Walkaway VSP,” Expanded Abstracts,74th SEG Annual International Meeting and Exposition,Denver (October 10–15, 2004): 2369–2372.Chiburis E, Franck C, Leaney S, McHugo S andSkidmore C: “Hydrocarbon Detection with AVO,” Oilfield Review 5, no. 1 (January 1993): 42–50.

13. Dutta NC, Borland WH, Leaney WS, Meehan R andNutt WL: “Pore Pressure Ahead of the Bit: An IntegratedApproach,” in Huffman A and Bowers G (eds): PressureRegimes in Sedimentary Basins and Their Prediction,AAPG Memoir 76. Tulsa: AAPG (2001): 165–169.

14. Sanchez A and Schinelli M: “Successful 3D-VSP on LandUsing Two Wells Simultaneously,” Expanded Abstracts,77th SEG Annual International Meeting and Exposition,San Antonio, Texas (September 23–28, 2007): 3074–3078.

Tucano basin

Riacho deBarra field

Recôncavo basin

km 250

miles 250

S O U T H A M E R I C A

B r a z i l

> Double-well 3D VSP acquisition design. More than 2,700 shot points were planned on lines over a13-km2 area. The area covered joins two circles centered on two wells (right). Shot locations arecolor-coded from low elevation (blue) to high elevation (red). A velocity model from existing 3Dsurface seismic data (left) was useful in planning the 3D VSP. In the velocity model, low velocities areblue and high velocities are red. (Modified from Sanchez and Schinelli, reference 14.)

N

> The Riacho de Barra field, onshore Brazil. A cross sectioninterpreted from well logs (top) shows the main reservoir (yellow)and the lower target (orange). Both are truncated at their uppersurfaces by erosion and are overlain by a conglomerate thatobscures seismic signals. After a 3D surface seismic survey failed toadequately image the erosional truncation, Petrobras acquired a 3DVSP to better delineate the limits of the reservoir. (Modified fromSanchez and Schinelli, reference 14.)

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and drilling the 4-m [13-ft] shot holes for deploy -ment of the dynamite sources. Rugged topog raphyand a forested landscape added difficulty to theacquisition campaign. No rig was available ateither well location, so a crane was mobilized todeploy the long receiver tools.

Because data recording requires good couplingbetween receiver and formation, the two wellswere evaluated for cement bond quality. A well-intervention team performed cement squeezes inboth wells to guarantee transmission of signalsfrom the formation through the cement and casingto the accelerometer receivers in the well.

Before acquisition of the 3D VSPs, a 115-levelconventional VSP was acquired in each well. Thequality of recorded data helped optimize thedepth location of the VSI arrays for the 3Dacquisition, and the velocity information fromeach well was used to facilitate processing of the3D VSP.

To reduce complexity of data processing, the3D VSPs from each well were handled separately,and then merged before the final stage ofmigration. The imaging results show an increasein resolution over that of the 3D surface seismicdata (above). Interpreters are currently workingwith the new 3D VSP data to define the limits ofthe reservoir.

28 Oilfield Review

15. “Thunder Horse: No Ordinary Project,” http://www.bp.com/genericarticle.do?categoryId=9004519&contentId=7009088 (accessed October 8, 2007).

16. Camara Alfaro J, Corcoran C, Davies K, Gonzalez Pineda F,Hill D, Hampson G, Howard M, Kapoor J, Moldoveanu Nand Kragh N: “Reducing Exploration Risk,” OilfieldReview 19, no. 1 (Spring 2007): 26–43.

17. Ray A, Hornby B and Van Gestel J-P: “Largest 3D VSP in the Deep Water of the Gulf of Mexico to ProvideImproved Imaging in the Thunder Horse South Field,”Expanded Abstracts, 73rd SEG Annual International

Meeting and Exposition, Dallas (October 26–31, 2003):422–425.Jilek P, Hornby B and Ray A: “Inversion of 3D VSP P-WaveData for Local Anisotropy: A Case Study,” ExpandedAbstracts, 73rd SEG Annual International Meeting andExposition, Dallas (October 26–31, 2003): 1322–1325.Pfau G, Chen R, Ray A, Kapoor J, Koechener B andAlbertin U: “Imaging at Thunder Horse,” ExpandedAbstracts, 72nd SEG Annual International Meeting andExposition, Salt Lake City, Utah, USA (October 6–12,2002): 432–435.

Inline, Crossline and Time Slice

3D VSP Cube

700 m

Surface Seismic Section 3D VSP

> Thunder Horse field in the Mississippi Canyon, Gulf of Mexico (left). BP ran several 3D VSPs in this area, which has numerous salt intrusions that reduce the effectiveness of surface seismicsurveys. Three-dimensional VSPs can be designed so that many raypaths avoid propagation throughthe salt (right).

New Orleans

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> Petrobras 3D VSP results. The borehole survey produced high-resolution results that can be interpreted using software designed for3D surface seismic data interpretation, including cube displays (topleft), and inline, crossline and time-slice displays (bottom left). Theresolution of the 3D VSP data was superior to that of the surfaceseismic data over the same area (right).


Autumn 2007 29

Gulf of Mexico 3D VSPsAn example of a marine VSP comes from the BP-operated Thunder Horse field in the south-central Mississippi Canyon, Gulf of Mexico. Thefield is in water depth of approximately 6,300 ft,[1,920 m], and is home to the largest mooredsemisubmersible rig in the world.15

Seismic imaging in the area is extremelycomplicated because of the abundance of over -lying salt bodies. Resolving structural complexityand stratigraphic detail is necessary for success,but difficult with 3D seismic data because the salt obscures major subsalt targets. Three-dimensional surface seismic data suffer fromwater-bottom and salt-sediment multiples, andfrom attenuation at the deeper reservoir levels.

Three-dimensional VSPs can be designed toreduce wave propagation through the salt(previous page, bottom). Avoiding raypathsthrough the salt eliminates some of thechallenges inherent in conventional surfaceseismic surveys. And with VSPs, the reflectedenergy travels a shorter path, reducingattenuation and improving resolution. The true3D geometry also produces data from a widerange of azimuths, a feature that improvesillumination in surface seismic surveys.16

Day rates for deepwater drilling rigs are high,and 3D VSP acquisition can take several days toa few weeks, so the operation must be efficient.At the time of the first 3D VSP in Thunder Horse,a VSI tool with 12 three-component shuttles wasavailable, the most that could be run. Standardpressures and temperatures were expected:17,400 psi [120 MPa] and 275°F [135°C].17

The first 3D VSP was completed in February2002 in the Mississippi Canyon 822-3 Well. The12-shuttle VSI tool was positioned at threeconsecutive depths to produce an effective 36-level VSP. A spiral source pattern was selectedfor efficiency, and repeated for each receiver-array depth, firing approximately 30,000 shots,and generating more than one million traces(above right). The image was found to be muchsuperior to the available surface seismic data,with markedly higher resolution, less noise andfewer artifacts (right).

Using the multilevel VSI tool enabledefficient and cost-effective acquisition of 3D VSPdata around targeted wells. High-resolutionimages from these VSPs can be used to guideplacement of development wells, and imagesfrom multiple wells can be combined to give amore comprehensive image of the subsurface.

> Spiral 3D VSP. A spiral shooting pattern included operation of a dual-source array and flip-flop shooting, with the source vessel first firing asource on the port side (blue dots), then a source on the starboard side(green dots). The spiral was repeated for each receiver-array depth.(Modified from Ray et al, reference 17.)

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> Comparison of 3D VSP results with a 3D surface seismic line. The 3D VSPdata (left) show higher resolution everywhere compared with surfaceseismic data (right). (Modified from Ray et al, reference 17.)

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Marine 3D VSPs can even be run without adrilling rig. One example comes from the GreenCanyon area of the Gulf of Mexico, where acomplex salt body overhanging the Mad Dog fieldcreated a shadow zone that made it difficult toobtain a clear image from surface seismic data.18

After casing was set at TD, a well in the field wastemporarily abandoned, and the rig was moved todrill another well from the same deck. To acquirea 3D VSP in the first well, a wireline winch,capstan and acquisition unit were installed onthe aft end of the semisubmersible’s main deck.Through this opening, a 20-level VSI array with100-ft [30-m] spacing between shuttles was runinto 4,500 ft [1,370 m] of open water and thencaught and guided into the subsea wellhead by aremotely operated vehicle (ROV). A video feed ofthe operation allowed the winch man and loggingengineers to coordinate tool deployment with theROV operator.

Once the receiver array was in place, dataacquisition continued efficiently, with nononproductive time. The source vessel, theWesternGeco Snapper, towed a three-gun arrayand shot two walkaway lines, and then shot thespiral survey geometry. The VSI system acquiredthe 32,000-shot 3D VSP in six days. BP realizedsubstantial savings by not using rig time for the acquisition.

Results from the Mad Dog 3D VSP helpedproduce an improved image in an area wheresurface seismic data had been affected by over -hanging salt (above left). Interpreters delineateda fault of approximately 1,640-ft [500-m] throwthat had caused an early well to completely missthe pay interval. Of three wells drilled into thestructure before the availability of the VSP, onehit the target in the right place, and logs from allthe wells corroborated the fault location and dipinterpreted from the borehole seismic data. BPdetermined that the cost of drilling two of thesidetracks could potentially have been saved if the 3D VSP had been acquired before drillingthe first well.

Optimizing Hydraulic Fractures in Real TimeBorehole seismic tools have been used since the1980s to detect seismic energy generated byhydraulic fracture treatments.19 The goal is to useknowledge of the fracture geometry and spatialdevelopment to help improve fracture operations.20

The ability to make decisions that can optimizestimulation treatments relies on two mainrequirements: receiving accurate informationabout fracture propagation in time to changeongoing operations, and having the technology toeffect the desired change.

30 Oilfield Review

> Rigless 3D VSP in the Gulf of Mexico. While the rig was being used todrill one well, a 3D VSP was performed in another well by running a 20-levelVSI tool through a false rotary on the aft end of the semisubmersible deck(left). In an image from the VSP data, a large-throw fault (purple) explainswhy some wells drilled into the structure did not hit the pay zone (red). Well 1 encountered the fault but failed to reach the reservoir. Well 2intersected a small portion of the pay zone, and Well 3 hit the pay in thecorrect location. Fault location and dip information from dipmeter logs (blue)confirm the fault interpretation on the VSP image. (Modified with permissionfrom Hornby et al, reference 18.)

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> Estimated stimulated fracture networks and a horizontal well in theBarnett Shale formation. Vertical wells (circles) penetrating the BarnettShale produce from stimulated areas approximated by the shaded areas(left). The operator drilled a horizontal well (black line) to tap undrainedareas. The wellbore trajectory (right) dipped low at the heel of the well thenrose 30 ft [9 m] over the 2,000 ft [610 m] between heel and toe. The fiveperforation clusters in the toe section of the well (red and green) are theentry points for Stage 1 of the hydraulic fracture treatments. Blue dots arethe entry points for Stage 2.

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Horizontal Wellbore TrajectoryBarnett Shale Production Areas


Autumn 2007 31

To address the first requirement,Schlumberger has developed an innovativehydraulic fracture monitoring technique thatprovides stimulation engineers with real-timeinformation pertaining to the geometry anddevelopment of hydraulically induced fracturenetworks. Real-time results allow operatingcompanies to make timely decisions to alter thefinal geometry of fractures and reduce or preventsuch undesirable situations as water production,overlap with previous treatments, fluid loss anduneconomic pumping.

The ability to change the outcome of astimulation treatment depends on the problemat hand. If the fracture is developing out of itsplanned zone, a decision can be made to end thejob. If the treatment is not reaching the desiredintervals, pumped fluids can be adjusted to sealcompeting zones. Diversion technology caneffectively bridge fracture systems and createadditional complex fractures.

One operator used StimMAP hydraulicfracture stimulation diagnostics to track theprogress of a multistage fracturing operation in ahorizontal well in the Barnett Shale. Thisformation in the Fort Worth basin of north-central Texas is the most active gas play in theUnited States. The Barnett Shale formation is a naturally densely fractured, ultralow-permeability reservoir that requires a largehydraulic fracture surface to be effectivelystimulated, and hence be economic.

The horizontal infill well was drilled in thedirection of minimum principal stress tofacilitate creation of transverse hydraulicfractures. The estimated stimulated fracturenetworks of several nearby hydraulicallyfractured vertical wells intersected the heel

section of the well (previous page, bottom).These regions of low stress caused by previousstimulation treatments will tend to attractpropagating fractures, making it potentiallydifficult to stimulate the toe of the well.

The treatment was designed to comprise twostages, with the first stage targeting fiveperforation clusters nearest the toe of the well.From the microseismic events localized inStage 1a, it is clear that the fracture developedaway from the higher stress interval near the toe,and extended toward the lower stress interval inthe heel, leaving the toe section understimulated(right). A diversion stage was pumped to try todivert the next treatment to the far perforations.Monitoring the seismic activity during Stage 1bindicated that again the toe section of the wellwas not fracturing, and again, stages of diversionfluid were pumped to try to divert fluid from thecompeting zones.

Inspection of the microseismicity maprevealed that seismic events were occurring nearthe first two perforation clusters, but not beyond.Coiled tubing was run to see if some type ofobstruction was preventing a fracture frominitiating between the second and thirdperforation clusters. Engineers determined thata sand plug was prohibiting stimulation in thatsection of the well.

After the sand plug was removed, Stage 1csuccessfully stimulated the toe section.Immediately, microseismic events were detectedin the previously unstimulated sections of thetoe. With additional diversion stages pumpedwhenever the real-time microseismicity ceasedto grow, the operator was able to stimulate the900-ft [274-m] toe section of the lateral withoutusing numerous time-consuming bridge plugsand perforating steps. A subsequent stagetreated the heel of the well, which was alsomapped by microseismic activity.

18. Hornby BE, Sharp JA, Farrelly J, Hall S and Sugianto H:“3D VSP in the Deep Water Gulf of Mexico Fills in Subsalt‘Shadow Zone’,” First Break 25 (June 2007): 83–88.

19. Albright JN and Pearson CF: “Acoustic Emissions as aTool for Hydraulic Fracture Location: Experience at theFenton Hill Hot Dry Rock Site,” SPE Journal 22, no. 4(August 1982): 523–530.

20. Fisher MK, Heinze JR, Harris CD Davidson BM, Wright CAand Dunn KP: “Optimizing Horizontal Completion Techniques in the Barnett Shale Using MicroseismicFracture Mapping,” paper SPE 90051, presented at theSPE Annual Technical Conference and Exhibition, Houston, September 26–29, 2004.Ketter AA, Daniels JL, Heinze JR and Waters G: “A FieldStudy Optimizing Completion Strategies for Fracture Initiation in Barnett Shale Horizontal Wells,” paper SPE 103232, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, September 24–27, 2006.Le Calvez JH, Klem RC, Bennett L, Erwemi L, Craven Mand Palacio JC: “Real-Time Microseismic Monitoring ofHydraulic Fracture Treatment: A Tool to Improve Comple-tion and Reservoir Management,” paper SPE 106159,presented at the SPE Hydraulic Fracturing TechnologyConference, College Station, Texas, January 29–31, 2007.

> Microseismic events mapped during progres-sion of hydraulic fracture treatments. Stage 1a(top) stimulated the region near the heel of thewell, but left the toe mostly unfractured. Diver-sion fluid was introduced to divert the nexttreatment to the perforation clusters at the toe.Stage 1b (second) also failed to stimulate the toe,and indicated an obstruction in the well betweenthe second and third perforation clusters. Follow-ing removal of a sand plug, Stage 1c (third)successfully stimulated the remaining 900-ft toesection. When all stages are plotted together(bottom), it can be seen that Stage 2 stimulatedthe heel section of the well (dark blue dots).

500 ft

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Obstruction

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Stages 1 and 2


Monitoring Perforating OperationsShell Exploration & Production was constructingproduction wells in the Cormorant field, UKNorth Sea. The wells were to be perforated withtubing-conveyed perforating (TCP) guns. Shellhad considered several methods of verifying TCPoperations, and decided to try monitoring theshots with a borehole seismic tool. In wireline-conveyed perforating, changes in cable tensioncan indicate that the guns have fired, and thiscan be confirmed when the guns are retrievedand inspected on the surface. In tubing-conveyedperforation, the guns may be left in the well andnever returned to the surface. Without positiveindications that the guns have fired, the onlyproof of the operation’s success is pulling thetubing and retrieving the guns, at great expenseto the operator.

Although the VSI tool is designed to recordborehole seismic surveys, the receivers are alsoable to detect signals generated by disturbancesin the vicinity of the borehole. The tool wouldundoubtedly be able to detect signals from asource as powerful as the shaped charges usedfor perforating if it were run in the same well.Unlike other borehole seismic tools, the VSI toolcan be used to acquire records of any timeduration. In typical deployment for logging

borehole seismic surveys, the recording length isset to approximately 5,000 ms and starts at theactivation of the controlled seismic source.However, for monitoring perforation shots, therecording system was set to begin recording oncethe tool had been anchored in position, and tocontinue recording until switched off by theseismic field engineer.

The wells were to be multilaterals with amain bore and one lateral bore. Typically, afterthe main bore was drilled and cased, more than 3,000 ft [910 m] of TCP guns were run to the reservoir interval and left in place, to be detonated by a trigger-delay system. Awhipstock—for exiting the casing to drill thelateral bore—was then set in the main wellboreabove the interval to be perforated. A VSI shuttlewas anchored 100 ft [33 m] above the whipstockto monitor the detonation of the perforating guns(above). After the firing of the guns and drilling,completing, perforating and cleaning up thelateral bore, the whipstock was perforated toallow the reservoir penetrated by the main boreto flow.

The VSI tool detected the sharp onset of signalfrom the perforation shots (next page, top). Thetool was close to the whipstock, and the largemagnitude of the signal saturated the dynamicrange of the recording system. Although the

amplitude cannot be read from the recording, anincrease in frequency of the signal can be detectedfor several seconds after the onset. Signal levelreturned to the level of background noiseapproximately 8 seconds after signal onset. Theseismic signals confirmed the successful firing ofperforation guns.

The primary purpose fulfilled, Shell engineersexamined the seismic data for additionalinformation. The guns had fired, and the emptyguns had filled with fluid. The return of theseismic signal level to background noise levelsindicated that fluids were no longer moving in thisportion of the borehole. The total duration ofsignal on the seismic record was interpreted torepresent the time it took the empty gun volumeto fill, and could be related to the inflow perfor -mance of the well. Given that the borehole belowthe whipstock is a closed system, and knowing thevolume of the perforating guns, effectively achamber at atmospheric pressure, Shell engineersincluded the time required to fill the guns in acalculation to obtain a rough estimate of absoluteopen-flow potential. With this additionalinformation from the seismic monitoring ofperforation shots, Shell engineers gainedunderstanding of reservoir behavior.

32 Oilfield Review

> Monitoring TCP operations with a borehole seismic receiver. Perforating guns were conveyed by coiled tubing, left on the bottom of the hole and set tofire with a long delay. After a whipstock was set, a VSI tool was deployed through drillpipe and anchored 100 ft above the whipstock. Detonation of theguns created seismic signals recorded by the sensors.

VSI tool

Whipstock Perforating guns


Autumn 2007 33

High-Pressure, High-Temperature SurveysWhile the VSI tool can log borehole seismicsurveys in most wells, high-pressure, high-temperature (HPHT) wells have specialrequirements. The seismic acquisition tooldeveloped for the SlimXtreme slimhole high-pressure, high-temperature well logging platformcombines high-performance packaging withanalog recording, minimizing the use of fragileelectronics (right). This 33⁄8-in. tool, like the othertools in the Xtreme family, was engineered tooperate in conditions up to 30,000 psi [207 MPa]and 500°F [260°C]. The short, lightweight sondewas designed with a single three-component setof receivers to handle checkshot surveys, but isnow also being used to acquire full VSP images inHPHT wells.

ConocoPhillips (U.K.) Limited had severalreasons for running the slim analog seismic toolin a challenging HPHT well drilled in the centralNorth Sea. The first was to generate an accuratetime-depth correlation between well data andthe time-based 3D marine seismic data over thetarget. While the reflection at the base of thechalk was clearly interpretable in seismicsections, the deeper reflection at the top of thereservoir was not as easy to pick. Correlationbetween VSP, well log and surface seismic datawould increase confidence in interpreting theshape and extent of the reservoir.

> Seismic recording of perforation shots andother events. This display is a continuous record,starting at the top, with the second line a continu-ation of the first, and so on. For each line, thevertical axis is signal amplitude. The signal fromthe perforation shots appears with a sharp onsetat 04:44:22. The signal saturates the dynamicrange of the recording system for several sec-onds. The recording returns to background noiselevels at 04:44:30, but some isolated noise burstsoccur earlier and later.

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Signal saturates completelyover this short duration ofrecording time Isolated noise burst about 6.7 s

after main energy burstReturn to background

noise levels at04:44:30, October 25

Random noise bursts observed aftercessation of main event. Magnitudeis down in the noise level.

> Borehole seismic acquisition tool for extreme conditions. The SlimXtreme slimhole high-pressure,high-temperature logging platform operates in conditions up to 30,000 psi and 500°F. Operatingcompanies have used the tool in conditions up to 238°C [460°F].

StandardSchlumberger

wireline unit

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Airgun


ConocoPhillips also wanted to acquire adepth-based VSP image of the reservoir intervaland layers below the well TD. In the surfaceseismic data, the dipping reservoir layers arepartially disrupted by noise from multiples,which appear as horizontal reflections thatinterfere with the signals from the reservoir.Because a VSP records both downgoing andupgoing waves and features multicomponentprocessing, a VSP image may contain fewermultiples and give a more accurate picture of thereservoir structure. And by extending the imagebelow the well, it would be possible to correlatehorizons beneath the reservoir with reflectionsseen on surface seismic data.

The third reason for acquiring VSP data wasto obtain better estimates of formation velocitiesfor improved reprocessing of the 3D marineseismic data. Reducing uncertainties in thevelocities of the chalk and underlying formationswould produce more accurate 3D images,potentially leading to reduced risk in futuredrilling in the area.

The slim analog seismic tool was the onlyoption for acquiring a VSP in the expectedpressure and temperature conditions. With TDbelow 15,000 ft [4,600 m], temperatures could beas high as 380°F [193°C]. The well trajectory was

deviated above the chalk, and then sidetrackedout of the plane of deviation as depth increased.

In spite of the extreme conditions, loggingproceeded smoothly. The tool acquired data atreceiver stations every 50 ft [15 m] spanning adepth interval from the reservoir up through thechalk, and also at more widely spaced intervalshigher in the section. At the deepest of the73 stations, temperature reached 380°F. Theseismic source comprised three 150-in.3 airgunsand was deployed at the rig in a zero-offset survey configuration.

Processing the three-component data todetermine where the reflections originatedincluded standard steps as well as a specialcorrection for the 3D nature of the boreholetrajectory. This would allow the VSP data to bemigrated using a 2D algorithm. The 3D trajectoryof the borehole was projected onto a verticalplane aligned with the shallow portion of the well(left). Reflection times, locations and amplitudeswere calculated assuming the VSP signals wereconfined to this plane, but in reality, somereflections occurred out of the plane. To takeaccount of this, raypaths and traveltimes for eachtrace were calculated using the 3D velocitymodel derived from initial surface seismicprocessing, and compared with raypaths andtraveltimes calculated from a 2D modelextracted from the 3D volume in the dominantvertical section chosen for processing. Thedifference between the two sets of computedtraveltime residuals was added as a staticcorrection to each trace prior to migration.

The differences in the velocity models alsoindicated that the VSP detected higher velocitiesin the chalk layer and lower velocities below thechalk than were seen in the surface seismicvelocity model. These differences translate intomis-ties observed between the VSP image andthe surface seismic image below the chalkinterval (below).

The depths of reflectors in the VSP image alsomatched those of a synthetic trace generatedfrom sonic and density well logs, confirming theaccurate depths of the VSP image in spite of theconflict between the 3D nature of the acquisitionobjective and the 2D approach to solve it (nextpage, top left). ConocoPhillips (U.K.) Limited isusing velocities obtained from the boreholeseismic survey to aid the reprocessing of existingsurface seismic data, and plans to use the slimanalog seismic tool in future HPHT wells.

Waves of the FutureBorehole seismic surveys have advanced farbeyond their origins as methods for convertingtime to depth for well-to-seismic correlations,although they are still used primarily for time-depth ties. As seen in this article, VSPs cansatisfy a wide variety of needs, providing 3Dimages of the subsurface, contributing tooptimized hydraulic fractures, verifying perfo -rating operations and obtaining high-quality datain HPHT conditions.

34 Oilfield Review

> Trajectory of the ConocoPhillips North SeaHPHT well. In this plan view, the source positionis a blue sphere, the receivers in the boreholeare green dots, and the reflection points on thetarget are in shades of blue and white. Theupper portion of the well follows an azimuth ofN61E, then veers to the northwest with depth.The source-receiver geometry and traveltimeswere projected onto a vertical section alongN61E to define a single azimuth with which tomigrate the data.

61°

> Comparison of VSP results with surface seismic data. The surface seismic image produced usingchalk velocities that are too low (left) fails to tie with the VSP (right). (The VSP is a small region withhigher amplitudes and higher resolution than the surface seismic image, and narrows upward.) Themismatch can be seen at several intervals.

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21. Hornby et al, reference 9.22. Djikpesse H, Haldorsen J, Miller D and Dong S: “Mirror

Imaging: A Simple and Fast Alternative to InterferometricMigration of Free-Surface Multiples with Vertical Seismic Profiling,” submitted to Geophysics, 2007.

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Autumn 2007 35

The future of VSPs will undoubtedly take manydirections. Hardware innovations will include newdownhole tools to withstand demanding condi -tions and new sources to enable even moreefficient acquisition. Permanent instal lation,allowing long-term reservoir monitoring, has beentested by some operators.21 Permanently installedtools could be used to conduct time-lapse surveysor to detect seismicity induced by production orinjection, even when deployed in the producing orinjection wells.

Other advances will come in processing toproduce better images from acquired data. Mostprocessing for creating images from VSP data hasborrowed from surface seismic methods. Butborehole seismic surveys, with their particulargeometries, offer opportunities that have notbeen fully explored.

One promising area is called interferometry,which is the interference of two or more waves toproduce an output wave that is different from theinput waves. Researchers are investigating waysto use interferometry to transform signalspreviously considered as noise into valuableinformation. For instance, in typical VSP dataimaging workflows, only primary reflections aremigrated. Free-surface multiple reflections areusually regarded as noise and thus eliminatedbefore migrating the recorded data. Whilebenefiting from reduced attenuation andimproved velocity control with respect tomigrated surface seismic data, the resultingmigrated VSP images are restricted to arelatively narrow zone of illumination lying belowthe borehole receivers. However, free-surface-related multiples contain valuable information

about shallower subsurface structures, and ifproperly migrated, they can provide widerillumination, and better vertical resolution of thesubsurface properties than when imaging usingprimaries alone (above).22

The early goal of VSPs was to reduce risk byenabling accurate time-to-depth correlationbetween surface seismic data and well logs.Current and future capabilities of boreholeseismic surveys still include risk reduction, butalso extend to improving recovery. –LS

>Matching reflector depths in a VSP image and a log-derived synthetictrace. One test of properly depth-correlated seismic data is matching witha synthetic trace generated from sonic and density well logs. In this case,the synthetic trace is plotted in yellow for visibility, and only positiveamplitudes are plotted, so as not to obscure the seismic data. Throughoutmost of the well, the positive amplitudes in the synthetic trace correlatewith those in the VSP, giving confidence in the projection assumptions madeduring processing. The VSP image extends beyond the bottom of the well.

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> Mirror imaging, an example of interferometry.The free surface and the area above it arereplaced by a mirror image of a medium with thesame elastic properties as the mediumcontaining the borehole and receivers. Receiversin the new material are the mirror image of theoriginal receivers. Whereas the original boreholeseismic experiment had a zone of illuminationrestricted to below the receivers, the mirroredexperiment has a zone of illumination thatextends to the former free surface.

Free surface

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Borehole Seismic Surveys: Beyond the Vertical Profile/media/Files/resources/oilfield_review/ors07/aut07/... · 20 Oilﬁeld Review Borehole Seismic Surveys: Beyond the Vertical Proﬁle