seismic tools for reservoir management
TRANSCRIPT
4
Seismic Tools for Reservoir Management
Reservoir engineers, geop t
the 3D seismic technique
there’s more to seismic th
seismic data can predict r d.
Here’s a look at some of th
toolbox—inversion, AVO, 3
guidelines for use and som
Tajjul AriffinGreg SolomonSalehudin UjangPETRONAS CarigaliKuala Lumpur, Malaysia
Michel BéeSteve JenkinsCaltex Pacific IndonesiaRumbai, Indonesia
Chip CorbettHouston, Texas, USA
Geoffrey DornRobert WithersARCOPlano, Texas
Hüseyin ÖzdemirGatwick, England
Chris PearseAmoco NorwayStavanger, Norway
For help in preparation of this article, thanCefola, Oryx Energy Company, Dallas, TexKeys, Mobil Exploration & Producing TechDallas, Texas; Andy Maas and Tiga TeilmaDuri, Sumatra, Indonesia; Robert North, GAnchorage, Alaska, USA; and Christopher Tensor, Houston, Texas.In this article RM (Reservoir Modeling) softof Schlumberger.
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InversionInversion is one of the foundations uponwhich reservoir geophysicists are buildingtools to make seismic information more use-ful to engineers. Inversion is so namedbecause it acts as the inverse of forwardmodeling. Forward modeling takes an earthmodel of layers with densities and veloci-ties, combines this with a seismic pulse, andturns out a realistic seismic trace—usuallycalled a synthetic. Inversion takes a realseismic trace, removes the seismic pulse,
hysicists, geologists and managers agree tha
can shed light on reservoir structure. But
an faults and layers: with the right handling,
ock and fluid properties across the whole fiel
e powerful probes in the seismic
D visualization and time-lapse surveys—with
e success stories.
ks to Davidas, USA; Bobnical Center,nn, GeoQuest,
Oil and gas companies large and small arelying on 3D seismic data to better deleate fields and identify new reserves. Opating companies have quantified and docmented the value a 3D survey can add to exploration or development project, copared to a 2D survey.1 These testimonidescribe the key role seismic images playrevealing reservoir locations and structurand the importance of using the informatiearly in the life of a field to derive maximubenefit.
But some companies are asking more their 3D seismic surveys, demanding knowedge beyond—in fact between—reflectioand getting it. A new science of reservgeophysics is emerging to provide this adtional information to reservoir engineerAt the heart of the matter are reservoir gephysicists, who rely on high-quality 3D sveys—available through advances in acqsition, processing and interpretatitechniques—for complete volume coveraof the reservoir. High-resolution borehoseismic surveys help fuse the surface seismwith log and core data to allow log propties such as lithology, porosity and fluid tyto be mapped field-wide (for an update s“Borehole Seismic Data Sharpen the Res
Oilfield Review
eoQuest,Ross, PGS
ware is a mark
voir Image,” page 18). With this more com-plete understanding of the reservoir, produc-tion engineers can optimize developmentand recover additional reserves. This articlereviews case studies of four techniques thatshow promise—inversion, amplitude varia-tion with offset (AVO), 3D visualization andtime-lapse monitoring.
and delivers an earth model of acousticimpedance (AI), or density times velocity, atthe trace location (next page). Seismic inver-
sion can be posed as a problem of obtainingan earth model for which the synthetic bestfits the observed data.3 The simplest earthmodels contain layers with densities andcompressional velocities, but more elabo-rate inversions yield models with shearvelocities as well. Ideally, inversions com-bine surface seismic, vertical seismic profile(VSP), sonic and density log data.
The main use of inversion for reservoirmanagement comes through log-propertymapping: the seismically derived AI valuesare tested for correlation with logs at thewell location—porosity, lithology, water sat-uration, or any attribute that can be found tocorrelate. Those log properties are then
Winter 1995
nForward modelingand inversion. Forward modelingbegins with anearth model ofacoustic impedance(AI) and ends witha synthetic seismictrace. Inversionbegins with a realseismic trace andoutputs an AImodel.
1. Jeffers PB, Juranek TA and Poffenberger MR: “3-D versus2-D Drilling Results: Is There Still a Question,” pre-sented at the SEG 63rd Annual International Meetingand Exposition, Washington, DC, USA, September 26-30, 1993, paper IM1.5.Greenlee SM, Gaskins GM and Johnson MG: “3-D Seis-mic Benefits from Exploration Through Development:An Exxon Perspective,” The Leading Edge 13, no. 7 (July1994): 730-734.Knecht SW and Helgeson S: “Case Study: How a SmallCompany Adopted 3D Seismic Technology,” Oil & GasJournal 90, no. 42 (October 19, 1992): 54, 56-57.Nestvold EO: “The 3D Seismic Revolution: Cost Bene-fits and Their Implications,” presented at the SEG Sum-mer Research Workshop on 3-D Seismology: IntegratedComprehension of Large Data Volumes, RanchoMirage, California, USA, August 1-6, 1993.Williams P: “Aces in the Hole,” Oil & Gas Investor(October 1994): 94.
2.“The Emerging Science of Reservoir Geophysics,” PetroSystems World (September/October 1994): 18-20.
3. Pan GS, Young CY and Castagna JP: “Net Pay Delin-eation of Gas Sand Using Integrated Target-OrientedPrestack Elastic Waveform Inversion,” presented at theSEG 63rd Annual International Meeting and Exposition,Washington, DC, USA, September 26-30, 1993, paperIM1.4.
800�
850�
900�
Tim
e, m
sec
Res
ervo
ir
Inputwavelet
Seismictrace
Forward modelingInversion
Estimatedwavelet
Earth modelof acousticimpedance
Earth modelof acousticimpedance
N
N o r w a y
S E A
Areaof detail
Denmark
Norw
ay
Denmark
UK
N O R T H
3°00'E 3°30'EAlbuskjell
Ekofisk
Tor
Gamma
TommelitenEdda
S. E. Tor
Eldfisk
Embla Valhall
MjØlner
WestHod
EastHod
Argyll
Norw
ay
Denmark
UK
West Hod East Hod
Norway
Denmark
2/11-3
2/11-A2
0 ft 3281
0 m 1000
extrapolated throughout the inverted 3Dseismic volume using the lateral variation ofseismically derived AI to guide the process.
Adequately processed seismic data are amust for inversion, but the optimum pro-cessing required to prepare data for inver-sion is the subject of much debate, as is theoptimal inversion calculation itself. Numer-ous processing chains have beendeveloped.4 A workshop was held recentlyto define the ultimate processing scheme,but to the surprise of the participants, noone method proved best.5 The trait that setsinversion apart from the standard processingchain for structural interpretation is the needfor preservation of true relative amplitudes.Changes in trace amplitude from one loca-tion to another may reveal porosity or otherformation property variations, but theseamplitude changes are subtle and may beobliterated by conventional processing.
Inversion can be performed before or afterthe seismic traces have been stacked—summed to create a single trace at a centrallocation—but care must be taken to ensurethat stacking does not alter amplitudes. Insome cases, such as regions where seismicreflection amplitudes vary with angle of inci-dence at the reflector, stacking does not pre-serve amplitudes, and inversion must be per-formed prestack. Only examples of poststackinversion results are presented in this article.
The simplest inversion scheme derives rel-ative acoustic impedance changes for oneseismic trace by computing a cumulativesum of the amplitudes in the trace. Thegradual trend of increasing AI with depth—invisible to seismic waves—is taken fromdensity and cumulative sonic travel times,and added to the relative AI results.6
Porosity Mapping in the Hod Field ChalksAmoco Norway in Stavanger has drawnupon seismic inversion followed by porositymapping as an aid to managing the devel-opment of the Hod field, the southern-most
6 Oilfield Review
4. Berg E, Brevik I and Buller AT: “Experiences Gainedusing a Seismic Inversion Method for Detailed Reser-voir Studies,” in Buller et al (eds): North Sea Oil andGas Reservoirs—II. London, England: Graham & Trot-man, Limited (1990): 129-138.Brac J, Déquirez PY, Hervé F, Jacques C, Lailly P,Richard V and van Nhieu DT: “Inversion With a prioriInformation: An Approach to Integrated StratigraphicInterpretation,” in Sheriff RA (ed): Reservoir Geo-physics. Tulsa, Oklahoma, USA: Society of ExplorationGeophysicists (1992): 251-258.Oldenburg DW, Levy S and Stinson KJ: “Inversion ofBand-Limited Reflection Seismograms: Theory andPractice,” Proceedings of the IEEE 74, no. 3 (March1986): 487-497.
5. SEG Workshop on Comparison of Seismic InversionMethods on a Single Real Data Set, Los Angeles, Cali-fornia, USA, October 28, 1994.
6. Schultz PS, Ronen S, Hattori M, Mantran P and Cor-bett C: “Seismic-Guided Estimation of Log Properties,”The Leading Edge 13, no. 7 (July 1994): 770-776.Ashcroft WA and Ridgway MS: “Early Discordant Dia-genesis in the Brent Group, Murchison Field, UKNorth Sea, Detected in High Values of Seismic-Derived Acoustic Impedance,” accepted for publica-tion in Petroleum Geoscience.
7. Pearse CHJ and Özdemir H: “The Hod Field: ChalkReservoir Delineation from 3D Seismic Data UsingAmplitude Mapping and Seismic Inversion,” presentedat the Norwegian Petroleum Society GeophysicalSeminar, Kristiansand, Norway, March 7-9, 1994.
Campbell SJD and Gravdal N: “The Prediction of HighPorosity Chalks in the East Hod Field,” Petroleum Geo-science 1 (1995): 57-69.Landrø M, Buland A and D’Angelo R: “Target-OrientedAVO Inversion of Data from Valhall and Hod Fields,”The Leading Edge 14, no. 8 (August 1995): 855-861.
8. The spillpoint is the point of maximum filling by hydro-carbon of a structural trap.
9. Acoustic impedance has the units of velocity timesdensity. Although the combination of English and met-ric units seems peculiar, ft/sec x g/cm3 is a commonunit.
nThe surface of the top chalk of the Hodfield in the Norwegian sector of the NorthSea. Most of the 66.9 MM barrels of oilequivalent attributed to the field liewithin the East Hod anticline. Additionalreserves have recently been provenbeyond the limit of structural closure,north of East Hod, where seismic ampli-tude, inversion and porosity mappingtechniques indicated the presence of ahigh-porosity reservoir zone.
in the trend of chalk oil fields in the Norwe-gian sector of the North Sea (previouspage).7 The two separate oil-filled anticlinalstructures in the field—West and EastHod—were discovered in 1974 and 1977,respectively. However, reservoir uncertain-ties were not resolved by appraisal drilling,and marginal economics delayed produc-tion until 1990. Total estimated originalreserves for the field are 66.9 million barrelsof oil equivalent (BOE), of which 94% areattributed to East Hod. An unmanned pro-duction platform is tied to the Valhall facili-ties to the north.
The primary reservoir interval at East Hodcomprises allocthonous—reworked andredeposited—chalks of the Tor formation.The 2/11-A2 well encounters a prime chalkreservoir section, with 90 m [295 ft] of Torformation showing porosities of up to 50%(below, right). Although East Hod is associ-ated with a pronounced anticlinal closure,oil is trapped not only structurally, but alsostratigraphically. Moveable oil has beenobserved below the established spillpoint,with reservoir distribution controlled by acombination of depositional, structural anddiagenetic factors.8 The complex interplaybetween these factors results in a highlyvariable chalk reservoir.
The top chalk surface represents an ero-sional unconformity that exposes a variety ofchalk types from the Ekofisk, Tor and Hodformations to the overlying Paleocene shaleseal. Well data show that chalks contributingto the top chalk seismic event have porositiesranging from 20 to 50%, with impedancesranging from 30,000 ft/sec X g/cm3 to 10,000ft/sec X g/cm3 [9150 to 3050 m/sec X g/cm3](top).9 The high-quality reservoir rocksexhibit a decrease in acoustic impedancecompared to the relatively uniform acousticimpedance of the overlying shale, whilenonreservoir chalks show an increase.Therefore the acoustic properties of thechalk exert the primary influence on the
7Winter 1995
nA crossplot show-ing correlationbetween porosityand acousticimpedance,derived from sonic,density and poros-ity logs from EastHod wells.
nThe 2/11-A2 East Hod well in a prime chalk reservoir section, with log and seismic datacompared to synthetics. Sonic slowness (track 2) and density data (track 3) are combinedto give acoustic impedance (track 4). This is combined with a seismic wavelet (track 6) toyield a synthetic trace (track 5), which matches the recorded surface seismic data at thewell (track 1). The acoustic impedance decrease at the top chalk interface produces ahigh-amplitude seismic peak, or swing to the right, in the polarity convention used here.
Por
osity
, %
60
50
40
30
20
10
010,000 20,000 30,000 40,000
Acoustic impedance, ft/sec x g/cm3
2/11-A2 East Hod
Two-
way
tim
e, m
sec
Well Trace
-0.1 0.1
Sonicµsec/ft
200 40 2 3g/cm3
Density AI
10,000 36,400ft/sec x g/cm3
SyntheticTrace
-0.1 0.1 -0.1 0.1
Zero-phaseWavelet
Topchalk
2550
2600
2700
2800
2650
2750
2850
2500
Acoustic impedance, ft/sec x g/cm310,000 36,00020,000 30,000
amplitude of seismic reflections, making itpossible to develop an effective method formapping the reservoir extent and qualityfrom inverted poststack seismic data.
Various 2D and 3D seismic inversion andporosity mapping techniques have beensuccessfully applied in the area. Because ofthe combination of the great range in chalkimpedance, and its predictable dependenceon porosity, the results of most inversiontechniques establish similar porosity trends,with the differences to be found in small
details and absolute porosity values.The first 3D porosity mapping at Hod field
was carried out using the Log-Property Map-ping module of the RM Reservoir Modelingsystem. Vertical well 2/11-3, with its excel-lent tie to the surface seismic data, was usedas the key well to calibrate the inversion(above). The other wells also provided inputto the low-frequency AI model and calibra-tion of AI to porosity.
This mapping supports the presence of azone of high porosity beyond the limit of the
East Hod structural closure (right). Subse-quent drilling in this area has confirmed theinversion predictions of commercial poros-ity, and a horizontal producing well is cur-rently draining the area which now repre-sents a proven extension of the Hod field.
An ever increasing functionality and qual-ity of applications are available for this typeof reservoir characterization. An example ofa significant refinement to the process usedin the Hod field area is a scheme calledspace-adaptive wavelet processing.10
Applied as a precursor to inversion, this pro-cess integrates information from many wellsto ensure that seismic data with a common,broadband, zero-phase wavelet are input tothe inversion.11 The resulting improvementin the resolution of the inversion and subse-quent interpretation have allowed porositymapping from seismic to become a standardpart of the chalk reservoir management pro-cess, and a primary means of identifying andquantifying the potential for extensions tothe field or separate accumulations nearby.
2/11-3 East Hod
Acoustic impedance, ft/sec x g/cm3
Well Trace
-0.1 0.1
Sonic
µsec/ft200 40 2 3
g/cm3
Density AI
10,000 36,400ft/sec x g/cm3
SyntheticTrace
-0.1 0.1 -0.1 0.1
Zero-phaseWavelet
2550
2600
2700
2800
2650
2750
2850
Topchalk
Two-
way
tim
e, m
sec
2500
10,000 36,00020,000 30,000
nAverage porosity mapped from seismicdata at East Hod, generated by the Log-Property Mapping application in the RMReservoir Modeling system. The plottedporosity values correspond to the averagein a 32-msec time window of the seismicdata. This corresponds to an intervalabout 40 to 55 m [131 to 180 ft] thick atthe top of the interpreted chalk section,and includes the optimum Tor formationreservoir. The white line indicates the lim-its of structural closure.
nLog and seismic data compared to synthetics in the key well 2/11-3. Tracks are as inthe figure on previous page, bottom. At the shale-top chalk interface, acousticimpedance increases. The synthetic and data traces respond to this with a high-ampli-tude trough—a swing to the left. This exploration well on the western flank of the EastHod encountered water-wet nonreservoir chalks.
8 Oilfield Review
10. Poggiagliolmi E and Allred RD: “Detailed ReservoirDefinition by Integration of Well and 3-D SeismicData Using Space Adaptive Wavelet Processing,”The Leading Edge 13, no. 7 (July 1994): 749-754.
11. Broadband means the bandwidth, or range of frequencies present in the wavelet, is wide. Zero-phase means the shape of the wavelet is optimizedfor interpretation of inversion results: trace peaksindicate locations of AI changes—in contrast toother kinds of wavelets, in which trace zeroes canindicate AI changes.
12. Corbett C, Solomon GJ, Sonrexa K, Ujang S and Ariffin T: “Application of Seismic-Guided ReservoirProperty Mapping to the Dulang West Field, OffshorePeninsular Malaysia,” paper SPE 30568, presented atthe 70th SPE Annual Technical Conference and Exhi-bition, Dallas, Texas, USA, October 22-25, 1995.
13. Anderson B, Bryant I, Helbig K, Lüling M and Spies B:“Oilfield Anisotropy: Its Origins and Electrical Char-acteristics,” Oilfield Review 6, no. 4 (October 1994):48-56.Ayan C, Colley N, Cowan G, Ezekwe E, Goode B,Halford F, Joseph J, Mongini A, Obondoko G, Pop Jand Wannell M: “Measuring Permeability Anisotropy:The Latest Approach,” Oilfield Review 6, no. 4 (Octo-ber 1994): 24-35.
N
2/11-3
Line 800
Line 850
Porosity, p.u.18 38
Mapping Porosity in MalaysiaOnce thought to be useful primarily in car-bonate reservoirs because of a more recog-nizable porosity-acoustic impedance rela-tionship, inversion for porosity mapping hasalso proven powerful in sand reservoirs.PETRONAS Carigali, the upstream operat-ing arm of the Malaysian national oil com-pany, has used seismic inversion to opti-mize drilling locations in the Dulang Westfield in the Malay basin of the South ChinaSea (right).12
The Dulang field has an estimated 850million barrels original oil in place (OOIP).In the first stage of development, more than100 wells were drilled in the central area ofthe faulted anticlinal structure, producingfrom an oil and gas column of up to 150 m[492 ft] of stacked sandstones. The nextstage of development focuses on the DulangWest portion, in which plans call for 25wells from a 32-slot platform.
The four delineation wells indicate areservoir too complex to understand fromwell data alone. The main reservoirs arefine-grained, discontinuous sands interbed-ded with shales and coals. The sand bodiesare preferentially oriented, suggesting per-meability anisotropy on the scale of thefield.13 Porosity, permeability and their rela-tionship to each other show great variabil-ity—for example, permeability can varyfrom 50 to several hundred millidarcies for amedian porosity of 25%. In the central areadeveloped earlier, close well spacing per-mitted property mapping from logs. But inDulang West, engineers have relied oninversion of the 3D seismic data to extendinformation contained in the delineationwells to map porosity across the field.
After the poststack seismic and log datawere tied at the right depths and inverted foracoustic impedance, log properties weretested for their correlation with the AI valuesat the respective well locations using theLog-Property Mapping module of the RMReservoir Modeling software (right). Onlyporosity was found to correlate significantlywith acoustic impedance, with a trend simi-lar to that of the chalks of the East Hod field.Extending the log porosity values away fromthe four wells using the seismic inversionresults as a guide produced a reservoirporosity map.
nCorrelation between average acoustic impedance (AI) and two log properties, poros-ity and gamma ray. Porosity shows an inverse correlation—AI decreases as porosityincreases, while gamma ray shows no significant correlation with AI.
Cambodia
Viet
nam
Thailand
Malaysia
Mala
ysia
Sumatra
Java
Singapore
Dulangfield
Borneo
SO U THC
HI N
AS
EA
GULF OFTHAILAND
Laos
Myanmar
N
Dulang field
Westernarea
Unitarea
Easternarea
6G-1.36G-1.4
6G-1.1B
6G-1.6
6G-1.2
0 miles 3.1
0 km 5
Por
osity
, p.u
.
20
15
10
5
0
18,000 20,000 22,000
6G 1.3
6G 1.6
6G 1.46G 1.2
6G1.1B
6G 1.36G 1.6
6G 1.46G 1.2
6G 1.1B
18,000 20,000 22,000
GR
, AP
I uni
ts
85
90
95
100
105
110
Acoustic impedance, ft/sec x g/cm3
9Winter 1995
nThe Dulang West fieldoperated by PETRONASCarigali, the upstreamoperating arm of theMalaysian national oilcompany.
An integrated assessment of porosity andstructure allowed interpreters to proposedrilling locations (above). Areas of higherporosity in the south were deemed morepromising than lower-porosity areas in faultblocks to the north. The Well Prognosismodule of the RM system allowed severalpotential sites to be quickly investigated forreservoir quality and likely reserves.
The reservoir model built from the seismicdata included not only the traditional aspectof reservoir structure, but also the total vol-ume of porosity in each volume element ofthe seismic cube. This model was scaled upfor input to a fluid-flow simulator. Perme-ability was distributed throughout the modelby applying a porosity-permeability trans-form to the seismically guided porosity map.
The new model provided a better estimationof production over a simulated seven-yearperiod than that obtained by other methods.
In addition, areas of high acousticimpedance were interpreted to be shaly orto have poor reservoir development,enabling better placement of planned wells.Recent appraisal drilling southeast of well6G-1.3, testing oil potential downdip of gasinferred from an especially low AI anomaly,encountered 18 m [59 ft] of good quality,18% porosity gross sand. Although the sandwas wet, agreement with the model wasgood, with 18.8 m [62 ft] and 19% porositypredicted. Two development wells, D1 andD2, further demonstrate the predictivepower of the method (below).
AVOIn some environments, seismic reflectionamplitude variation with offset (AVO) can beused as a reservoir management tool to indi-cate hydrocarbon extent.14 The AVO tech-nique relies on the observation—backed upby physics—that pore fluid type imprints asignature on the amplitude of a seismicreflection. To see this signature, seismic datamust be viewed at different angles of reflec-tion. Depending on the type of pore fluid inthe juxtaposed rock layers, the amplitude ofthe reflection may increase, decrease, orremain constant as the reflection angle at theboundary increases (below). The incidentangle of the seismic wave can be expressedin terms of offset, or distance, between seis-mic source and receiver—a congruent quan-tity more easily measured than an angle atsome depth.
A common way to use AVO to character-ize reservoirs is to identify a hydrocarbonAVO signature—for example, the AVOresponse of a gas reservoir—and comb the3D seismic volume for other areas with sim-
10 Oilfield Review
nWest Dulang seismically guided porosity map and proposed drilling locations (greendots). Comparisons between predicted and actual drilling results are shown in the table(below).
nAmplitude variation with offset (AVO).Some interfaces show AVO signatures, orvariation of reflection amplitude withangle of incidence. In this case, theamplitude increases with offset.
aaaaaaaaaaaaaaaaaaaaAmplitude increases
Amplitude variation with offset (AVO)
CommonMidpoint
(CMP)
Shale
Gas sand
S4 S3 S2 S1 R1 R2 R3 R4
Offset 3
Offset 2
Offset 1
Offset 4
Offset 3
Offset 2
Offset 1
Offset 4
Appraisal6G1-7
Well
DevelopmentD1
DevelopmentD2
Thickness
18.8 m
15.4 m
13.4 m
Porosity
ActualPredicted ActualPredicted
18 m
16.6 m
6.3 m
19%
19.8%
17.5%
18%
20%
18%
Porosity, p.u.13.69 20.00
6G 1.3
6G 1.6
6G 1.4
6G 1-7
6G 1.1BD1
D2
ilar signatures. This can result in discoveriesof bypassed hydrocarbon as well as exten-sion or delineation of existing reservoirs.The practice assumes that lithology does nothave enough lateral variation to affect theseismic amplitudes, so that all AVO effectsare due to changes in pore fluid type. Theseismic data must be processed to preserverelative amplitudes, and also must be ana-lyzed before stacking.
Some lithologies show less obvious AVOsensitivity to pore fluid change than others.Carbonates and low-porosity sandstonestend to have less evident AVO signaturesthan high-porosity sandstones, and specialcare must be taken in applying the technol-ogy in these areas.15
In an example from the mature BK field inthe Gulf of Mexico, the successful incorpo-ration of AVO analysis helped Oryx EnergyCompany engineers identify extensions ofthe reservoir that might have gone undrilled.The quality of the AVO results convincedmanagement to free up money for drillingthat had been allocated elsewhere.
The BK field lies off the flank of a shallowsalt and shale diapir in 5 m [16 ft] of waternear the Louisiana Gulf Coast (above right).The reservoir, discovered in the late 1940s,has produced 300 billion cubic feet (Bcf) ofgas. The map of the 5000-m [16,400-ft]deep structure had been constructed primar-ily with well control, and the new 78-km2
[30-square mile] survey, designed to provideincremental structural and stratigraphicinformation, changed the structural map sig-nificantly (right).
AVO analysis was introduced to betterdelineate the gas reservoir and reduce riskin choosing drilling locations. The analysisrequired a seismic cube for two differentfamilies of offsets. Data processing followedthe same sequence as for the full 3D cube,except the data were separated into a near-
11Winter 1995
nStructural maps created before and after the 3D survey showing significant differ-ences. Well BK-15 produces gas. BK-16 is a proposed well location in an undrilled updipfault block. (Adapted from Ross CP, reference 14, courtesy of Blackwell Science.)
U N I T E D S T A T E S
LouisianaMississippi
Alabama
Texas Mis
siss
ippi
Riv
er
G U L F O F M E X I C O
3D surveyarea
BK-16Line 1235
Line 1215BK-15
Before 3D Survey After 3D Survey
14. 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.Ross CP: “Improved Mature Field Development with3D/AVO Technology,” First Break 13, no. 4 (April1995): 139-145.
15. Lu HZ and Lines L: “AVO and Devonian Reef Explo-ration: Difficulties and Possibilities,” The LeadingEdge 14, no. 8 (August 1995): 879-882.Ross CP and Kinman DL: “Nonbright-Spot AVO:Two Examples,” Geophysics 60 (September-October1995): 1398-1408.Hall DJ, Adamick JA, Skoyles D, DeWildt J andErickson J: “AVO as an Exploration Tool: Gulf ofMexico Case Studies and Examples,” The LeadingEdge 14, no. 8 (August 1995): 863-869.Peddy CP, Sengupta MK and Fasnacht T: “AVO Anal-ysis in High-Impedance Sandstone Reservoirs,” TheLeading Edge 14, no. 8 (August 1995): 871-877.
nThe BK field oper-ated by OryxEnergy Companyoff the LouisianaGulf Coast.
offset volume with offset ranges from zeroto 3800 m [12,468 ft] and a far-offset vol-ume with offsets from 3800 to 5800 m[19,024 ft] (left).
Forward modeling using logs from pro-ducing wells indicated the gas zones havean AVO signature of amplitude increasingwith offset. Interpretation consisted of find-ing other areas in which the near-offset vol-ume has low amplitudes and the far-offsetvolume has higher amplitudes.
The technique is demonstrated on a pair ofseismic lines extracted from the 3D volume.The AVO signature on Line 1215 at the gas-producing well BK-15 is the standard towhich Line 1235 is compared to determinethe likelihood of hitting gas at the proposedlocation BK-16. A color-coding system wasdevised to discriminate increasing AVOtrends from decreasing ones (below left ).Results of the analysis show the BK-16 loca-tion to be similar to, and perhaps even morepromising than, the producer BK-15 (below).
Initial production from the BK-16 well was15.4 MMcf/D and 210 barrels of condensateper day from 25 m [82 ft] of 20% porositysand. Sand quality is better than that foundin the BK-15 well, refuting speculation thatsand quality degrades to the northwest. Andfollowing the BK-16 well, two additionalsuccessful wells have been drilled within theregion of AVO gas signature.
12 Oilfield Review
Far offsets
Offset 3Offset 4
Offset 2Offset 1
21Near-offset
stack
43Far-offset
stack
Near offsets
CMP
CMP
Far-offset cube
Near-offset cube
BK-16Line 1235
Line 1215BK-15
nConstruction of near-offset and far-offset cubes. Offsets less than 3800 m [12,464 ft]are stacked to create a trace in the near-offset cube, and offsets from 3800 to 5800 m[19,024 ft] are stacked to form a far-offset volume.
nThe AVO signa-ture at the gas pro-ducer and at theproposed welllocation. Red indi-cates amplitudeincreasing with off-set (near offsetssmaller amplitudethan far offsets) atthe top of the reser-voir and yellowindicates the sameresponse but forthe bottom of thereservoir. Thedesired AVO signa-ture, as seen at theBK-15 location, is ared-over-yellowsequence at 3.7sec. The same sig-nature is present atBK-16, indicatingthe likelihood offinding gas there.(Adapted from RossCP, reference 14,courtesy of Black-well Science.)
nReservoir quality map for the BK fieldcreated from AVO analysis. Qualityincreases from gold to orange. (Adaptedfrom Ross CP, reference 14, courtesy of Black-well Science.)
3.2
3.4
3.6
3.8
4.0
3.2200 250 300 350
3.4
3.6
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Seeing is BelievingSometimes just seeing the interpreted seis-mic data from a new point of view can shedlight on reservoir complexities and helpengineers plan and manage development.With the arrival of powerful graphics work-stations, visualization has become a key ele-ment in integrated reservoir characterizationstudies. Workstation visualization allowssimultaneous display of data from varioussources and enhances the communicationof ideas and problems among technical per-sonnel and management. Visualization itselfcan at times reveal something about thereservoir that was not previously suspectedor understood.
Examples from ARCO operations in thePickerill field in the southern North Sea gasbasin demonstrate the value of 3D visualiza-tion as a tool to help in well planning(above ).16 Early drilling revealed someobstacles to effective field development.First, reservoir porosity varies between lessthan 8% and greater than 20%, and the lat-eral variation is quite rapid—the reservoir is
highly faulted, and even small-throw faultscan create barriers to flow of gas, due todiagenesis along the fault surfaces. Second,a discontinuous dolomite floats within theZechstein evaporites overlying theRotliegend reservoir. Exploration drillingmet with overpressure problems when thewells penetrated the dolomite, while over-pressure was not encountered when theborehole avoided the dolomite. The over-pressure represents a drilling hazard and apotential cost to be avoided.
Visualization techniques used as part of areservoir characterization study helpedtackle these problems. A highly detailedreservoir fault interpretation was developedby combining an attribute of the seismicdata—the reflection strength—with theinterpreted structure in a 3D display (left,top). By casting a light on the 3D surface,which was colored according to reflectionstrength, interpreters were able to pick faultswith a vertical component of displacementas small as 3 meters [10 ft].
Planning safe well trajectories in areaswith dolomite sheets, locally known as Plat-tendolomit, can be optimized with 3D visu-alization. By simultaneously viewing thesurface of the top of the Rotliegend reservoirand of the Plattendolomit, proposed welltrajectories can be assessed for safety. A pro-posed well that penetrates the Platten-dolomit can be redirected to avoid overpres-sure problems (left, middle and bottom).
As part of the reservoir characterizationstudy, interpreters derived a correlation
13Winter 1995
Pickerillfield
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nLocation of the Pickerill field, operatedby ARCO, in the southern gas basin of theNorth Sea.
nTop: seismic reflection strength colorcoded on the surface of the faulted reser-voir. Middle: visualization of drilling tra-jectories. Bottom: verifying the trajectoryof an alternative well path planned toavoid the Plattendolomit. Dolomite “float-ing” above the reservoir can be mappedto assess the risk of well paths intersect-ing this overpressure hazard.
16. Dorn G, Cole MJ and Tubman KM: “Visualization in3-D Seismic Interpretation,” The Leading Edge 14,no. 10 (October 1995): 1045-1049.
Plattendolomit
Plan View
Well Projection
Optimized Well Trajectory
Top Reservoir
Top Reservoir
Approximatereservoirboundary
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0.6 miles
between seismic reflection strength andporosity determined from well logs, thenmapped the lateral variation in porosity onthe reservoir surface (below). These displaysintegrate the estimated porosity and struc-tural information and present it in an easilygrasped, intuitive manner.
The results have been used to help guidethe location of development wells in thePickerill field. In four wells drilled withinthe first year after completion of the study,the actual porosity encountered—between11% and 15%—was slightly higher thanthat predicted, but well within the error ofthe techniques used.
Time-Lapse SeismicIf conditions are favorable, seismic surveysacquired at different times in the history ofthe reservoir can show how fluid fronts havemoved.17 The knowledge of fluid distribu-tion can help engineers identify unsweptzones and plan infill or injection wells tooptimize recovery.
To detect fluid changes, the differences inreflection amplitude or travel time of theseismic waves must be discernible abovedata noise levels. The rock properties thatinfluence seismic reflection response—den-sity and velocity—must show significantvariation with fluid content, pressure or tem-
perature. The seismic surveys must alsohave acquisition and processing as similaras possible to ensure that all observed differ-ences can be interpreted as changes relatedto production. Accuracy and repeatability oftime-lapse seismic surveys may be signifi-cantly improved by using permanent sen-sors, either on land or on the seabottom.
Time-lapse seismic, sometimes called 4D,has proved an important tool for reservoirmanagement for Caltex Pacific Indonesia inthe Duri field of central Sumatra (next page,top left).18 The Duri field, with 5.3 billion bblOOIP, was expected to produce only 8% ofthe OOIP under primary recovery. Optimizedsteamflooding could bring ultimate recoveryto 60%—an incremental recovery of morethan 2 billion barrels of oil. Knowing wherethe heat is being placed in the reservoir iscritical to optimize the recovery. With thesereserves at stake, Caltex turned to a seismicmonitoring pilot study to understand thecomplex flow patterns in shallow Duri reser-voir rocks, and to evaluate the method’s suit-ability for large-scale application.
Laboratory tests on core samples indi-cated the steamflooding would reduce seis-mic velocities by up to 40%—a 15%decrease due to increased temperature, andat the highest temperatures, an additional25% reduction because of a water-to-steamphase transition (below).
14 Oilfield Review
nColor-codedporosity on a 3Dimage of the reser-voir surface. Visu-alization helpedlocate wells byavoiding faultingand tapping highporosity. Actualporosity encoun-tered was slightlyhigher than pre-dicted.
nLaboratory results showing effect of tem-perature and pressure on seismic velocitiesof core samples. Steamflooding can reducevelocities by up to 40%—a 15% decreasedue to increased temperature, and at thehighest temperatures, another 25% fromthe water-to-steam phase transition.
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The seismic survey required a specialdesign, and all source and receiver parame-ters were tested in the field prior to the base-line survey to allow resolution of the shal-low 500-ft [152-m] target depth andoptimum repeatability (top, right).
The baseline survey was recorded onemonth before steamflooding. Full acquisi-tion and processing for the small 0.06-km2
[0.02-square mile] survey took about oneweek. The survey was repeated five times inthe next twenty months (above).
Zones affected by the introduction ofpressure, temperature and steam can be rec-ognized in the monitor surveys. Seismicvelocities in zones surrounding the injectorwere so much slower than before treatmentthat the layers appeared to thicken and sagin the seismic images—an illusion createdby the increased travel time in those layers.
17. Albright J, Cassell B, Dangerfield J, Deflandre J-P,Johnstad S and Withers R: “Seismic Surveillance forMonitoring Reservoir Changes,” Oilfield Review 6,no. 1 (January 1994): 4-14.
18. Bée MF, Jenkins SD, Lyle JH and Murhantoro E: “4-DSeismic: A Powerful New Technology for MonitoringSteam Movements in Duri Field—Central Sumatra,”presented at the 23rd Annual Convention of theIndonesian Petroleum Association, Jakarta, Indone-sia, October 4-6, 1994.
15Winter 1995
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InjectornCaltex Pacific Indonesia’s Durifield of central Sumatra. The 3Dseismic survey geometry calledfor high-density sampling overthe pilot steamflood area.
nSeismic data from the baseline survey and five monitor surveys. As steamflooding proceeds, decreased velocities in treated layerscause an apparent sag in reflectors. The top yellow line tracks the reflection at the top of the reservoir, and the bottom yellow linetracks the reflection at the oil-water contact.
Baseline 2-month lapse 5-month lapse 9-month lapse 13-month lapse 19-month lapse
Zones farther from the injector showed avelocity increase at early times, because ofthe passage of the pressure front precedingthe arrival of the fluid.
The high-pressure and trailing high-tem-perature fronts spread asymmetrically fromthe central injector, indicating a high-per-meability trend heading north and west(right). Temperature data from two observa-tion wells and core-calibrated permeabilitylog data corroborate the presence of thefront and the permeability anisotropy sug-gested by the seismic data.
The seismic data were further examinedfor evidence of vertical sweep efficiency.Thermal effects were tracked in three differ-ent layers by correlating the percentagevelocity change in each layer with a devia-tion from ambient temperature (next page).The top layer was interpreted to have thelowest sweep efficiency, the middle layer tohave the highest, and the bottom layer inbetween. Prior to steamflooding, an inde-pendent reservoir quality analysis on corefrom the formations showed the same hier-archy: the top layer, with the most clay con-tent, was estimated to be the worst zone, themiddle layer the best and the bottom layerin between.
Encouraged by the feasibility demonstratedin the pilot study, Caltex has begun to imple-ment the technology on a large scale in theDuri field. The next phase, with the base sur-vey already shot in April 1995 and the firstmonitor survey planned in early 1996, cov-ers 35 injector patterns instead of one.
16 Oilfield Review
nPlan view of front movement at the time of each monitor survey. Travel time to thetreated zone is compared between the baseline survey and each subsequent survey(first five blocks of figure). A decrease in velocity is seen as a pull down—the reflectorappears pulled down—while an increase in velocity pulls the reflector up. The asym-metrical spread indicates a high-permeability trend to the north and west. The oil satu-ration distribution that would result after 19 months of steamflooding was simulated,and shows good agreement with the location of the steam front imaged at that time(last block of figure).
12 msec 12 msec
Pull up Push down
10% 55%Oil saturation
After 2 months After 5 months After 9 months
After 13 months After 19 months After 19 months
Growing FieldsSeismic surveys can provide a wealth ofinformation beyond the structural frameworkfor which they are best known. However, thisis not yet a routine operation, and has to becarried out with care, using seismic and welllog data together, and a technique appropri-ate to the problem. Porosity and lithology canbe mapped from inversion results, and fluidcomposition can be predicted using AVOanalysis. Visualization is key when structureis complex, and time-lapse monitoring isappropriate when reservoir rock propertiesare sensitive to fluid changes.
Surveys need to be acquired, processedand interpreted quickly to make significantcontributions to the study. Some of the newtechniques are expensive, and they must bejustified. The additional information createsno value unless it changes the way a field isdeveloped or managed. Typically, however,only a small fractional increase in hydrocar-bon productivity is required to justify a seis-mic project in reservoir applications.
As fields mature, operators place greateremphasis on improving the profitability ofexisting assets through increased productionand improved efficiency. With this trend,reservoir geophysics will become morewidely used to extend field life and maxi-mize recovery. The field of reservoir geo-physics is developing to address the integra-tion of data of many scales and of differentphysical properties. More advances will bemade by trying the techniques in untestedareas and pushing the limits. —LS
17Winter 1995
nThermal effects tracked in three differ-ent layers to assess sweep efficiency. Thetop layer, Upper Pertama, was interpretedto have the lowest sweep efficiency, andthe middle layer, Lower Pertama, to havethe highest. Sweep efficiency of the deep-est formation, the Kedua, is between theother two. Reservoir quality analysis oncore from the formations showed thesame hierarchy.
TemperatureAmbient100° F
Steam375° F
Upper Pertama
Lower Pertama
Kedua (deep)
132° F 100° F
237° F 167° F
104° F 112° F