IPA-117.Fault Seal Integrity the Timor Sea Area Prediction of Trap Failure Using Well-constrained...

8/16/2019 IPA-117.Fault Seal Integrity the Timor Sea Area Prediction of Trap Failure Using Well-constrained Stress Tensors and…

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IPA01-G-021

PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATIONTwenty-Eighth Annual Convention & Exhibition, October 2001

FAULT SEAL INTEGRITY IN THE TIMOR SEA AREA: PREDICTION OF TRAP

FAILURE USING WELL-CONSTRAINED STRESS TENSORS AND

FAULT SURFACES INTERPRETED FROM 3D SEISMIC

D. A. Castillo*

D. J. Bishop**

M. de Ruig**

ABSTRACT

Drilling in the Laminaria High and Nancar Troughareas has shown that many hydrocarbon traps are

underfilled or completely breached. Previous studieshave shown that fault-trap integrity is stronglyinfluenced by the state of stress resolved on thereservoir bounding faults, suggesting that carefulconstruction of a geomechanical model may reducethe risk of encountering breached reservoirs inexploration and appraisal wells. The ability of a faultto behave as a seal and support a hydrocarbon columnis influenced in part by the principal stress directionsand magnitudes, and fault geometry (dip and dipazimuth). If a fault is critically stressed with respectto the present-day stress field, there is a high

likelihood that the fault will slip, thereby re-creatingfault zone permeability that enables hydrocarbons toleak. Leakage could be intermittent depending on thedegree and rate of fracture healing, and on therecurrence rate between reactivated slip events.

High-resolution wellbore images from over 15 wellshave been analyzed to construct a well-constrainedstress tensor. Constraints are based on geomechanical parameters, along with drilling conditions that areconsistent with the style of drilling-inducedcompressive and tensile wellbore wall failure seen in

each of these wells. This regional stress analysis of permits AC/P8, AC/P16, Zone of Cooperation andsurrounding areas indicates a non-uniform strike-slipstress regime (SHmax > Sv > Shmin) with theorientation of the maximum principal horizontalstress (SHmax) varying systematically from N-Scompression in the northern reaches to NE-SWfarther south. ___________________________________________________________

* GeoMechanics International Inc.** Woodside Energy Ltd.

Fault surfaces interpreted from 3D seismic data have been subdivided into discrete segments for the purpose of calculating the shear and normal stressesin order to resolve the Coulomb Failure Function

(CFF) on each fault segment. Hydrocarbonaccumulation (column height) and leakage (residualcolumn) deduced from well results may be explainedin part by the CFF resolved on their respectivereservoir-bounding faults. By integrating thegeomechanical model with fault imagingtechnologies, explorationists and reservoir engineerswill gain the ability to use these predictive tools tohelp quantify the likelihood of encountering a breached reservoir prior to drilling.

INTRODUCTION

Drilling in the AC/P8, AC/P16 and adjacent blockswithin the Timor Sea area has shown that manyreservoir fault traps have experienced hydrocarbonleakage. Following the discoveries of the Laminariaand Corallina Fields, exploration activity within thegreater AC/P8 and AC/P16 areas (including WA-260-P and ZOCA 91-01) has produced a commercialsuccess ratio of 13% and an oil discovery rate of 35%.A majority (67%) of the unsuccessful explorationwells in the area show evidence of a residual or

palaeo hydrocarbon column, indicating trap breachingas the main cause of exploration failure and sub-commercial finds. In every case within the Timor Seaarea, the sealing integrity of these structural faulttraps depends largely upon a top seal of sufficientquality and thickness to support the buoyancy forcesexerted by the hydrocarbon column, and the capacityof the reservoir-bounding fault(s) to behave as animpermeable seal or baffle to thwart lateral fluidmigration or vertical migration along the fault.


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implying that the Australian continent is travelingabout 20% faster than Timor Island. The majortectonic expressions of this convergence in theIndonesia area are the partial subduction of theAustralian plate, pervasive reverse faulting, and thedevelopment of an accretionary prism on Timor

Island. Several major NE-SW left-lateral strike-slipfaults that span the Banda Arc-Timor Sea providesupportive evidence of oblique convergence (e g.,Sumba Fracture Zone). Strike-slip faulting appears to be contemporaneous based on the 1997 M6.3Cockatoo Earthquake (insert in Figure 1).

Exploration wells within AC/P8 and AC/P16 havetargeted Middle to Upper Jurassic sandstonereservoirs in structural traps on the margins of the Nancar Trough and Laminaria High (Figure 2). Withthe exception of the Laminaria and Corallina

discoveries, the drilling programme has beendisappointing. The Barnacle -1, Vidalia-1, andClaudea-1 wells (Figure 1) encountered little to nodirect evidence for hydrocarbon shows, implying alack of charge to these structures. Ludmilla-1, whichtested a Nancar Sandstone Member tilted fault-blockclosure, encountered a 4 m live oil column overlyinga 50-70 m long residual oil column. The Mandorah-1well (Figure 1) tested a Montara/Laminaria Formationtilted fault-block closure but failed to encounter anyhydrocarbons. The structure is interpreted to havehad access to oil charge, but the lack of recoverable

hydrocarbons is attributed to either the inability of the bounding faults to support a hydrocarbon column or aleaky fault along the migration pathway. Fannie Bay-1 and Lameroo-1 tested the Laminaria Formation intwo distinct tilted fault-block closures and were foundto be water-bearing with residual oil saturations only.Both structures are interpreted as having retainedsizeable oil columns (in the case of Fannie Bay-1, inexcess of 80 m) which have since leaked. The Mindil-1 well was drilled along the structural trend of theLudmilla-1 oil discovery. The well failed toencounter any moveable oil, although the possible

presence of residual hydrocarbons is suggested fromlogs. A detailed description of the hydrocarbonexploration history of the Nancar/Laminaria area ofthe Timor Sea, can be found in De Ruig et.al., (thisvolume).

STRESS ANALYSIS METHOD

Determining the relationship between the seismicallydetected regional faults and the in-situ state of stress

involves constructing a well-constrainedgeomechanical model. This was accomplished byreviewing available drilling information, pressuredata, and high-resolution microresistivity andultrasonic wellbore images from over 15 wells todetermine the magnitudes and orientations of the

principal tectonic stresses (SHmax, Shmin and Sv)and pore pressure (Pp) distribution within the AC/P8and AC/16 areas. The magnitude of the greatest principal horizontal stress (SHmax) was calculatedusing GMI•SFIB™ (Stress and Failure of InclinedBoreholes) by forward modelling the style of stress-induced compressive and tensile wellbore wall failureas observed in each of these wells. The orientation ofthe greatest horizontal principal stress is parallel tothat of tensile failures (tensile wall fractures) and perpendicular to that of compressive failures(breakouts) in these near-vertical wells. The

magnitude of the least principal horizontal stress(Shmin) was determined from extended leak-off tests(XLOT) and leak-off tests (LOT), while themagnitude of the vertical stress (Sv) was simplycalculated based on density data collected in severalrepresentative wells.

For a more complete description of the methodologyused in this study, the following original references based on applying these techniques worldwide arehelpful (Haimson and Fairhurst, 1967; Bell andGough, 1979; Zoback and Healy, 1984; Plumb and

Hickman, 1985; Zoback et al., 1985; Moos andZoback, 1990; Zoback and Healy, 1992; Barton et al.,1995; Castillo and Zoback, 1994; Peska and Zoback,1995; Barton et al., 1998).

AC/P8 AND AC/P16 STRESS STATE

Over 5000 cumulative metres of high-resolutionwireline log image data and 4-arm caliper data have been reviewed in order to identify stress-inducedcompressive and tensile wellbore failures in about 15

wells within AC/P8, AC/16 and surrounding areas.This information provided the basis upon which to build the geomechancial model. To accurately assessthe uniformity of the stress field, we supplementedthis study with analysis of pressure data, well logs,and other data from over 22 wells in the area. Resultsindicate that the greater AC/P8 and AC/P16 area isgenerally characterised by a strike-slip faultingregime (SHmax > Sv > Shmin) in which the verticalstress is the intermediate stress. Pressure data and


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drilling information indicates that the pore pressureregime within the reservoir is approximatelyhydrostatic throughout the area.

SHmax stress orientation

The quality of the image data ranged from good toexcellent. Representative examples of wellborefailure seen in the analyzed wells include the drilling-induced tensile wall fractures from Laminaria -2 (Fig.3), and wellbore breakouts from Claudea-1 (Figure 4)and Lameroo-1 (Figure 5). In addition to thewellbore breakouts shown in Figures 4 and 5, tensilewall fractures were also seen elsewhere in these wellsand were oriented close to 90 degrees to the directionof the breakouts. Despite the regional variation inSHmax stress directions, each particular wellindicated a relatively uniform stress orientation from

about 1,000 to 4,000 mTVD. Wellbore breakouts inthese study wells were relatively symmetric with breakout widths ranging from 40° to 70°. The breakout width describes the angular coverage of the borehole wall that failed in compression resulting inthe rock spalling from the wellbore.

The orientation of the maximum principal horizontalstress (SHmax) varies systematically between theAC/P8 and AC/P16 blocks (Figure 1). Details ofSHmax stress orientations from the individual wellswere analysed using azimuthal statistics (Mardia,

1979) and are listed in Table 1. The regional SHmaxstress direction in AC/P8 (Laminaria High) is 15°N ±6° (Figure 6a); while further south in AC/P16, theSHmax stress direction changes to about 63°N ± 6°(Fig. 6b). This marked transition occurs along thenorthern reaches of the Nancar Trough (Figure 1).The SHmax stress direction in the northern part of thestudy are is remarkably sub-parallel to other stressindicators seen in the northern section of ZOCA(Castillo et al., 1998) as well as being sub-parallel tothe relative convergence direction between Indonesiaand Australia (Figures 1 and 2). This transition in

SHmax stress orientation to the south is nearlyidentical to the stress rotation previously reported forthe western part of ZOCA (Castillo et al., 1998).

The systematic variation in SHmax stress directions between the AC/P8 and AC/P16 areas is not clearlyunderstood. That the regional SHmax stress directionin AC/P8 (Laminaria High) area is subparallel to theconvergence direction between Australia andIndonesia (Figure 2), suggests that present-day

horizontal plate motion direction influences thedirection of the maximum horizontal principal stressin this area. The marked rotation in SHmax beginning in the Nancar Trough and continuing intothe Londonderry High suggests that othermechanisms are responsible for the systematic

variation in stress directions seen in the greaterAC/P16 area. Interestingly, the relatively uniformSHmax stress direction seen within the NancarTrough and Mallee Terrace appear to besystematically different from directions seen in theCartier Trough and Londonderry High area (Figure2). The generalized SHmax stress direction in the Nancar Trough and Mallee Terrace is approximately65°N, while SHmax in the Cartier Trough andLondonderry High is about 30°N. This regionalvariation may be related to a major transition in theregional fault trends at the Aptian Unconformity

level. Faults in the Nancar Trough and MalleeTerrace area trend roughly E-W, while in the CartierTrough and Londonderry High area the prevailingfault trend is NE-SW (Figure 2). This mutuallysystematic rotation in both the SHmax stress directionand regional fault trends in the greater AC/P16 areawould suggest that the regional tectonic patterns areinfluencing the regional stress state. A more thoroughexamination of the stress state in the AC/P4 area(southwest of AC/P16) and ZOCA 96-16 (east of 91-12) may help understand if these apparent ‘stress provinces’ distinct from the northern part of the study

area, are influenced by fault geometry .

Pore pressure, vertical stress, and Shmin

Direct measurements of formation pore pressure (Pp)in AC/P8 and AC/P16 on wells analyzed in this studyare limited. Reservoir formation pore pressure wasgenerally considered to be normal and estimated torange between 1.03 and 1.04 SG. The vertical principal stress (Sv) was determined by integratingdensity logs collected in AC/P8 and AC/P16 wells.

The magnitude of the regional minimum horizontal principal stress (Shmin) in AC/P8, (includingAC/L5), AC/P16 and surrounding areas is inferredfrom formation integrity tests (FIT) in 5 wells, LOTsin 13 wells, and an XLOT in Claudea-1 (Figures 7and 8, Table 1). A FIT generally provides only alower bound on the fracture gradient, which may not be equivalent to the minimum principal stress. In thecase of AC/P8, the Shmin stress magnitude can beassumed to be approximately equal to the leak off


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pressure because LOT results from these verticalwells indicate a fracture gradient that is lower than thevertical stress. The most robust measurement ofShmin in the AC/P8 area was collected during anXLOT in the Claudea-1 well at a depth of about 2750mTVD. Stress profiles of pore pressure, vertical stress

and Shmin values for the study area are shown inFigures 7 and 8, respectively. Without exception allmeasurements (FIT, LOT, and XLOT) indicate anShmin that is considerably less than the verticalstress. The thin dashed line in Figures 7 and 8represents a best fitting approximation of Shmin placing more weight on the LOT and XLOT ratherthan the FIT, for reasons described above. Theseresults quantify four of the five unknown parametersof the in-situ stress field (the magnitudes of Sv, Pp,Shmin, and the orientation of SHmax). To determinethe remaining parameter (the magnitude of the

maximum horizontal stress, SHmax) requires a moredetailed analysis of wellbore failures from imagelogs.

However, it is possible to use the existing data to predict whether SHmax is greater or less than Sv, based on the ratio between the effective vertical andleast horizontal stresses. For instance, frictionalconstraints on the differential effective stressmagnitudes are limited by re-occurring slip onoptimally-oriented faults assuming a Mohr-Coulombfailure criteria (Jaeger and Cook, 1979), namely

(S1-P p)/(S3-P p) [(µ2+1)1/2 + µ] 2 (1)

where µ is the coefficient of friction and S1 > S 3. In

seismically active regions, in-situ stressmeasurements using hydraulic fracturing techniqueshave confirmed that these laboratory constraints onstress magnitudes are generally correct using µ values between 0.6 and 1.0 (Byerlee, 1978; McGarr, 1980;Zoback and Healy, 1984; Zoback and Healy, 1992).In this paper we have used µ =0.7, well within the0.6-1.0 range observed by Byerlee (1978).

Applying this to the top of the Laminaria (or Nancar)Formation at an average depth of 3,200 m, thefrictional equilibrium relationship between Pp,Shmin, and Sv is (Sv-Pp)/(Shmin-Pp) ~ 2.62 (Jaegerand Cook, 1979). This is significantly less than avalue that would cause slip along optimally-orientedfaults in a normal faulting stress regime based on

laboratory-derived coefficients of friction

(Byerlee, 1978). Therefore, while a least principalstress that is less than the vertical stress could indicatea normal faulting stress regime (i.e., Sv > SHmax >Shmin), we will show next that the style of wellborefailure seen in AC/P8, AC/P16 and surrounding blocks can not be explained by a normal faulting

stress regime. In particular, we find that a strike-slipstress regime (i.e., SHmax > Sv > Shmin) is not onlyconsistent with the style of wellbore failure, but isalso consistent with local tectonics associated with present-day convergence between the Australian andthe Indonesian plates (Wilson et al., 1998; Shuster etal., 1998; Simmons et al., submitted), and recentearthquake activity (National Earthquake InformationCenter web site, Fredrich et al., 1988).

Absolute magnitude of SHmax

To constrain SHmax stress magnitudes, we use theGMI•SFIB™ module CSTR (Constrain Stress) atseveral depths between about 1,000 and 4,100 mTVDin AC/P8 and AC/P16 to forward model thecompressive (breakouts) and tensile (tensile wallfractures) wellbore failure seen in the various wells(Figures 3, 4 and 5). We also used GMI•SFIB™module BSFO (Borehole Stress and FailureOrientation) to evaluate explicitly how boreholegeometry, rock strength, and stress conditions at the borehole wall lead to the observed style of wellborefailure. Additional input parameters required for this

analysis included the magnitudes of Sv and Shmin,Pp, the mud weight, temperature, and wellboretrajectory. Figures 9 and 10 show representativeexamples of how GMI•SFIB™ was used in this study.

Figure 9 presents the results of the analysis for theClaudea-1 well at about 2,900 mTVD where tensilewall cracks were detected, but no breakouts wereobserved. The figure plots the magnitude of Shmin onthe x-axis and the magnitude of SHmax on the y-axis.The polygon constrains the horizontal stressmagnitudes assuming the crust is in frictional

equilibrium (Equation 1). The blue contoursrepresent the magnitudes of the two horizontalstresses required to induce tensile failure for a giventensile strength (contours) and drilling conditions.Because drilling-induced tensile fractures wereobserved in this interval, the stresses must lie abovethe blue contour corresponding to a finite effectivetensile strength of the rock. In the absence of strengthmeasurements, the contour corresponding to To=0 provides a lower bound on SHmax. The least


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horizontal stress, constrained by XLOT and LOTs is predicted to be approximately 43.7 MPa. Thecombination of the frictional faulting constraint andthe constraint imposed by the presence of tensilefailures limits the magnitude of SHmax at this depthto be 79.0 +/- 7.8 MPa. The red contours delineate the

unconfined compressive strength required to prevent breakouts from occurring for the given magnitudes ofthe two horizontal stresses at this depth. The absenceof breakouts in this interval requires that theunconfined compressive strength must be greater than95 MPa (Figure 9 and Table 1).

Figure 10 shows a forward model of drilling-inducedcompressive (wellbore breakouts) and tensile (tensilewall fractures) failure seen in the Lameroo-1 well atabout 3,900 mTVD. The resultant stress distributionaround the borehole is shown in Figure 10a indicating

that breakouts would be about 55 degrees wide, whichis consistent with the breakouts seen in the STARimage data. Breakouts will occur when the maximumcircumferential stress exceeds the uniaxialcompressive strength of the rock. The missingcolours in Figure 10a correspond to sections in thenear-wellbore region that would be in tension, whichis also consistent with observations of the drilling-induced tensile wall fractures in Lameroo-1. Figure10b is a modelled “unwrapped” view of the boreholewall showing the location and width of the breakoutsas they are seen in image data. Figure 10c is again a

model of the borehole wall, and plots the position ofthe inclined tensile wall fractures as they appearwithin the Lameroo-1 well.

Modelling wellbore failure in the Claudea-1,Lameroo-1 and other wells in the greater AC/P8 andAC/P16 areas, reveals that the magnitude of SHmaxis consistently in excess of Sv (Figures 7, 8, 9, 10, andTable 1). This implies that this section of the TimorSea area is subject to a strike-slip stress regime(SHmax > Sv > Shmin). This strike-slip stress state is

consistent with results from a regional trap integritystudy (Castillo et al., 1998) where it was found that astrike-slip stress regime exists within ZOCA 91-01and much of ZOCA 91-12, which is also consistentwith recent strike-slip earthquake activity (e.g., 1997M6.3 Cockatoo Earthquake). Inferences based onstructure, kinematic, and geodetic studies also suggestthat the Timor Sea Area is subject to obliqueconvergence between Australia and Timor Island

resulting in strike-slip deformation (Shuster et al.,1998; Wilson et al., 1998; Simmons et al., submitted).

DISCUSSION: IMPLICATIONS FOR FAULTTRAP INTEGRITY IN THE AC/P8 AND AC/P16

AREAS

Many of the wells drilled in the AC/P8, AC/P16,ZOCA, and surrounding regions encounteredsignificant residual oil columns, implying that theassociated fault trap structures were optimally suitedfor hydrocarbon charge and retention early in thecharge history. This would further imply that thefaults bounding these reservoirs were not previouslycritically-stressed, thus preserving the fault seal gougematerial (formed by cataclastic grain-reducing processes associated with slip) within the fault zone.Subsequent to hydrocarbon charge and oblique

collision between Australia and Indonesia (Shuster etal., 1998), hydrocarbon leakage would have occurredalong specific faults that became critically-stresseddue to the change in the stress field.

The ability of a fault to behave as a seal is influencedin part by the principal stress directions andmagnitudes, fault dip and dip azimuth. If a fault iscritically stressed with respect to the present-daystress field, there is a high likelihood that the faultwill slip, thereby increasing the fault zone permeability and enabling hydrocarbons to migrate

from the reservoir. To explore this fault-stressrelationship, results of the in-situ stress analysisdescribed above have been integrated with detailedrepresentations of the faults interpreted from 3Dseismic data from the AC/P8 and AC/P16 areas.These interpretations of the reservoir fault surfaceswere depth converted and transformed into a series ofconnected fault segments, fully described in terms ofa 3D coordinate system, dip and dip azimuth for eachindividual segment. The shear and normal stressesresolved on each of these segments were calculatedusing GMI•MohrFracs™ in order to identify which

segments are critically-stressed in the present-daystress regime.

Fault segments which are critically-stressed areassociated with an applied shear stress that exceedsthe frictional strength of the fault plane. If thedifference between the shear stress and the frictionalstrength of the fault is positive, the fault may rupturedue to Coulomb shear failure, which can be expresses


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as the following Coulomb Failure Function (Jaegerand Cook, 1979):

τ - µ (S n – P p) = CFF (2) where τ is the applied shear stress, S n-P p is the

effective normal stress, µ is the coefficient of friction(Byerlee, 1978). The second term in Equation 2 is thefrictional strength of the fault surface.

An overview of two representative fault surfaces in‘stress space’ is shown in Figure 11 (Corallina Field)and Figure 12 (Fannie Bay). Figure 11 shows modelresults for two major faults in the Corallina Field area(Figure 2). There are critically-stressed faultsegments (red tadpoles, red poles in the MohrDiagram and white poles in the stereographic projection), associated with the north-dipping (east-

west trending) fault in the Corallina Field. Thesecritically-stressed segments appear to be restricted tothose few that are steeply-dipping (70°-75°) to theENE or NW (Figure 11a). A similar situation existsfor the south-dipping fault in the Corallina Field(Figure 11b). With the exception of the few faultsegments that dip to the southeast, there is a large population of SSE dipping fault segments which arenot optimally oriented for shear failure. BecauseSHmax is about 10°N in this area (Figure 2 and Table1) and the trend of the primary trap-bounding faults isE-W, the trap integrity of the overall reservoir faults

appears to be high (CFF is negative), which isconsistent with the presence of hydrocarbon in theLaminaria and Corallina Fields.

The pervasive presence of these high-angle faultssegments in the Fannie Bay and Lameroo areasindicate that many of the reservoir-bounding faultsmay be critically-stressed. The northward dipping(approximately E-W trending) reservoir-boundingfault adjacent to the Lameroo-1 well is shown inFigure 12. This particular fault segment has amorphologic shape with different fault dip segments

ranging from 50 to 70°. The high angle faults (dip >60°) are better suited for slip failure in a strike-slipstress regime, while fault segments which dip < 60°are not optimally oriented for shear failure.

Using 3D visualization technologies to display theCFF plotted as fault attributes on the individual faultsurfaces helps to understand this fault-stressrelationship. This analysis provides an opportunity toquantify the potential for shear failure on different

segments of the fault, and therefore, the likelihood offault trap failure. Figures 13 to 16 illustrate how thisstress-fault visualization analysis was used to evaluatethe trap integrity along the reservoir-bounding faulttraps in the Corallina Field, Fannie Bay, Lameroo andLudmilla structures in AC/P8, AC/P16 and

surrounding areas.

Corallina and Laminaria structures in AC/P8

Figure 13 is a oblique perspective view of theCorallina Field facing northeast, showing therelationship between the Top Laminaria Formationand the major faults defining the structural trap. Thecolour contours on the 3D seimic faults are the CFFfault attributes, based on the stress analysis describedabove (Figures 2 and 7, Table 1). Because theSHmax stress direction is approximately

perpendicular to the east-west trending faults, thesestructures are not critically-stressed since thefrictional fault strength of the fault exceeds theapplied shear stress resulting in a CFF that is less thanzero (see Equation 2).

A change in fault geometry, particularly the fault bounding the Corallina horst to the north, results in acorresponding change in the CFF resolved on thefault segment (Figure 13). The consequence of thischange in fault trend to a southeast dipping structureis a positive CFF (i.e., critically-stressed segment).

Interestingly, this fault attribute transition from non-critically-stressed to critically-stressed occursapproximately where the palaeo-oil-water contact inCorallina, defined on the basis of Grains Oil Inclusion(GOI) analysis (Figure 13), implying that the currentstress state may be controlling the maximum potentialhydrocarbon column height in the Corallina Fieldover geologic time. Because the Mohr-Coulombfailure criteria evaluate the static stress state along a particular fault segment, there may be crack growtheffects related to dynamic fault-slip propagationlinking a stable fault segment that is at the threshold

of shear failure. The current oil-water contact withinthe Corallina reservoir is up-dip from the paleo-oil-water contact, suggesting that there may have beensome dynamic slip propagation along the fault.However, we cannot rule out the possiblility thattemporal variations in stress and varying episodes ofcharge have not played a role in the currenthydrocarbon accumulation in the Corallina Field.

The results for the Laminaria Field also indicate that


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the main E-W bounding faults (Figure 2) are notcritically-stressed and would therefore, be capable ofsupporting the hydrocarbon column that exists in thefield. There is some limited evidence that asecondary population of NE-SW trending faultswithin the reservoir may be critically-stressed.

However, the resolution of the seismic data does not place strong constraints on the geometry and extent ofthese apparently minor fault segments (Smith et al.,1996).

Fannie Bay and Lameroo structures in AC/P16

The implications of this stress-fault analysis differregionally. Despite the consistency in fault structurethroughout the region (Figure 2), the rotation inSHmax from nearly N-S in AC/P8 to NE-SW in

AC/P16 produces an increase in applied shear stresson the ENE-WSW trending faults (compare Figures11 and 12). The net result of the poor fault trapintegrity of these charged reservoirs appears to be anearly complete discharge of the hydrocarbons.

Residual oil columns were detected in the FannieBay-1 and Lameroo-1 wells, implying that atsometime in the past the major faults were notcritically-stressed and were therefore, capable oftrapping hydrocarbons. A detailed examination of themajor reservoir-bounding fault within the Fannie Bay

structure indicates that the entire fault is critically-stressed, both above and below the top Laminariahorizon (Figure 14). The fault segment adjacent to theLameroo structure is critically-stressed above thehorizon, adjacent to the cap rock (Figure 14). Thefault that once supported a hydrocarbon column in theLameroo reservoir, but is now critically-stressed, mayhave initiated shear failure within the upper sectionsof the fault (adjacent to the cap rock) andsubsequently propagated downward towards faultsegments near the threshold of shear failure (Figure14).

Ludmilla and Mindil structures in AC/P16

Figures 15 and 16 illustrate this methodology appliedto the Ludmilla and Mindil area in AC/P16. Thesefigures show the top Nancar Formation along with themajor near-vertical faults and well locations.Coloured contours on the faults are the specific CFFattributes based on the stress tensor determined in this

study. Figure 15a shows a regional overview of thearea with the locations of the Nancar-1, Ludmilla-1and Mindil-1 wells. The view direction is to thesouthwest, sub-parallel to the local SHmax stressdirection of 53°N (Figure 2).

A close-up view of the top Nancar Formation in theLudmilla structure is shown in Figure 15b along withthe two major trap-bounding faults. The CFF isclearly different on each fault. The southwest dippingfault is not optimally oriented for shear failure and istherefore capable of supporting high trap integrity(i.e. CFF 0), particularlyalong the northeast segment of the fault where theCFF contours are shown in different shades of purple.The greenish-brown contours on this northwest fault,closer to the crest of the reservoir, represent sections

that are near the shear failure threshold. Thetransition to a positive CFF attribute (purple shades)along this section of the northwest faults marks theapproximate location of the palaeo-oil-water contact based on GOI analysis. Drilling results of theLudmilla-1 well indicated a live oil column overlyinga residual oil column with the current oil-watercontact situated several tens of metres above the palaeo-oil-water contact (Figure 15b).

The Mindil-1 well drilled a similar structure locatedfurther to the west (Figure 15a). A close-up view is

shown in Figure 16. Again, the fault bounding thereservoir to the north is critically-stressed (CFF > 0)suggesting that the probability of encountering a breached reservoir adjacent to this fault is high. TheMindil-1 well was drilled into the structural highsituated adjacent to the southern trap-bounding fault(left fault in Figure 16). The CFF associated with thisfault indicates that it is near the threshold of beingcritically-stressed.

Pore pressure -induced shear failure

It is possible to quantify what the critical pore pressure (Pp Critical) is required for an otherwisestable fault segment to fail in shear (Wiprut andZoback, submitted). The Pp Critical (Pp/Sv scale barin Figures 11 and 12) reflects the incremental increasein pore pressure required to decrease the effectivenormal stress enough to induce shear failure onsegments that are currently not critically-stressed.This is equivalent to replacing pore pressure (Pp) with


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the critical pore pressure (Pp Critical) in Equation 2.The current pore pressure regime normalized by thevertical stress (Sv) is about Pp/Sv ~ 0.4 (Figures 11and 12). Increasing the pore pressure within oradjacent to faults that are at the threshold of shearfailure (CFF slightly negative), would effectively

increase the likelihood of shear failure occurringalong these segments. Potentially, this could alsoextend the zone of slip failure from the segment thatis already critically-stressed and prone for failure.

If elevated pore pressure is to be considered a viablemechanism for enhancing the likelihood of shearfailure on segments that are currently at theirthreshold of failure, it is necessary to identify thesource and timing of the overpressure. However, thesource of the elevated fluid pressure does not

necessarily have to be within the reservoir. Theseelevated pore pressures can be unique to the faultzone and unrelated to the adjacent rock formations.Brines have been found to be associated with residualoil columns and faults (Lisk et al., 1999) which couldhave migrated from the same salt deposits laid downin the Early Palaeozoic (Shuster et al., 1998). Theseapparently high temperature, high pressure brinesmigrating upward from a deeper source alongcritically-stressed faults could provide a pulse of high pressure fluid leading to dynamic shear failure alongsegments at the threshold of shear failure (CFF

slightly negative).

Alternatively, the reservoir pore pressure in theLondonderry High, Nancar Trough, and LaminariaHigh areas at the time of hydrocarbon charge couldhave been elevated with respect to the present-day pore pressure. For instance, if the reservoir pore pressure exceeded Pp Critical fault slip would resultin a discharge of hydrocarbons, which wouldsubsequently lead to a decrease in reservoir pore pressure. If the pore pressure decreased to levels

below the critical pore pressure, then fault slip would be inhibited and a fault seal would begin to redevelop(i.e., secondary mineralization would heal the faultzone). Although this palaeo pore pressure mechanismis difficult to reconcile given the expanse of thereservoir sands in the region, it may be possible todetermine the paleo-reservoir pore pressure byconducting fluid inclusion analysis similar to Georgeet al. (1997) and Lisk et al. (1996).

CONCLUSION

Increasing our understanding of fault seal integrityrequires a well-constrained geomechanical model.This includes detailed knowledge of the principalstress magnitudes (SHmax, Shmin and Sv) and stress

directions, pore pressure, coupled with a detailedrepresentation of fault surfaces from depth-converted3D seismic data. If a fault segment is criticallystressed with respect to the present-day stress field,there is a high likelihood that the fault will slip due toshear failure, resulting in hydrocarbon leakage alongthe slip-induced fault zone permeability structure.

Quantifying the stress state in the AC/P8 and AC/P16areas indicates a non-uniform strike-slip stress regime(SHmax > Sv > Shmin) with the orientation of themaximum principal horizontal stress (SHmax)

varying systematically across the study area, similarto that previously reported for the western part ofZOCA. Within the AC/P8 region, SHmax is about15°N, while further south in AC/P16, the regionalSHmax stress direction systematically changes toabout 63°N.

Assessing some of the risks associated with trapintegrity in structures drilled in AC/P8 and AC/P16has been accomplished by combining details on thestress field with 3D representations of the importantfaults defining the traps. Evaluating the stress state

resolved on these faults to determine which faultsegments are critically-stressed, followed by 3Dvisualization to interpret the results, provides animportant exploration tool for assessing risksassociated with fault seal failure. Applying thisintegrated stress-fault approach to the Laminaria andCorallina Fields, and the Fannie Bay, Lameroo andLudmilla structures has greatly increased ourunderstanding of the mechanism(s) responsible forthe successful and not-so successful drillingenterprises in the Timor Sea area.

ACKNOWLEDGEMENTS

Author DAC is specially grateful for the opportunityto have worked with co-authors DJB and MdR atWoodside Australian Energy on this Timor Sea faultseal project. Extended thanks also to Marian Mageeand David Moffat for their constructive andsupportive comments.


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TABLE 1

Well Image SHmax Depth Shmin SHmax Co Name Data Stress mTVD (observed) (modelled) modelled

Direction MPa MPa MPa

Alaria-1 STAR 15°N ± 1° 2400 * 55.50 ± 5.0 85 ± 15Banka Banka-1 FMI 27°N ± 6° * * * *Cleia-1 * * 2115 31.71 * *

Claudea-1 STAR 7°N ± 1° 2750 41.48 * ** * 2900 * 79.01 ± 7.84 120 ± 25

Corallina-1 FMS 11°N ± 4° 883 10.99 * *2612 36.40 * *

3150 * 72.90 ± 7.40 80 ± 103250 * 76.44 ± 7.63 100 ± 253300 * 77.72 ± 7.72 102 ± 22

Fannie Bay-1 STAR 62°N ± 2° * * * *

* * 3007 45.38 * ** * 3340 * 78.73 ± 5.42 55 ± 25* * 3430 * 81.13 ± 5.43 32 ± 17* * 4100 * 97.71 ± 4.34 130 ± 20

Fulica-1 HDT 67°N ± 7° * * * ** * 1634 20.14 * *

* * 2100 * 48.00 ± 8.71 55 ± 20Halimeda-1 STAR 12°N ± 5° * * * *

* * 2900 * 76.60 ± 6.97 40 ± 20* * 3000 * 70.08 ± 7.08 37 ± 15* * 3200 * 76.60 ± 6.97 60 ± 20* * 3300 * 77.45 ± 7.41 62 ± 22

* * 3400 * 79.96 ± 7.48 55 ± 20Jarrah-1 FMS no failure * * * *

* * 1805 30.42 * *

Keppler-1 FMS 36°N ± 4° * * * ** * 1153 16.64 * ** * 1620 * 37.35 ± 3.65 50 ± 10

Kittiwake-1 FMS 77°N ± 4° * * * *

* * 2395 34.37 * ** * 2416 * 58.55 ± 5.57 80 ± 20

Lameroo-1 STAR 72°N ± 4° * * * *915 10.31 * *

2959 44.82 * *3885 * 91.00 ± 5.71 83 ± 133900 * 91.97 ± 5.07 105 ± 203926 * 92.90 ± 5.30 70 ± 10

Laminaria-1 * * 889 10.80 * ** * 2653 36.18 * *

Laminaria-2 FMI 24°N ± 2° * * * ** * 2406 31.65 * *

* * 3300 * 76.20 ± 6.16 82 ± 22* * 3350 * 77.48 ± 6.28 90 ± 20* * 3400 * 78.84 ± 6.37 95 ± 20

Laminaria-3 * * 2645 37.58 * *

Laminaria East-1 * * 2815 38.62 * *Lorikeet-1 * * * * * *

1614 25.15 * *Ludmilla-1 STAR 53°N ± 4° * * * *

* * 2160 30.23 * *3200 * 81.42 ± 7.02 95 ± 353500 * 89.27 ± 6.61 72 ± 28

Mallee East-1 * * 1772 26.05 * *

Mandorah-1 * * 3016 46.94 * * Nancar-1 * * 2040 30.79 * *Vidalia-1 STAR 19°N ± 6° * * * *

* * 797 10.39 * *

* * 2699 38.26 * ** * 1150 * 25.28 ± 2.30 34 ± 8* * 2000 * 45.98 ± 5.98 56 ± 16* * 2400 * 58.11 ± 5.32 75 ± 15

* * 2950 * 73.70 ± 5.47 95 ± 25


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FIGURE 1 – Regional stress map of the Timor Sea Area based on data within AC/P8 and AC/P16 and ZOCA. Stress indicators are represented by theinward-facing arrows showing the direction of the maximum principal horizontal stress (SHmax) in the ZOCA 91-01 and ZOCA 91-12areas (black stress indicators) after Castillo et al. 1998, and for the AC/P8 and AC/16 area (red stress indicators) based on this study.The black/white earthquake focal mechanism solution for the August 10, 1997 M6.3 Cockatoo Earthquake indicates nearly pure strike-slip fault movement on either NNE-SSW or NW-SE nodal planes. The large blue arrow represents the convergence direction between

Australia and Indonesia (Wilson et al., 1998). Well names abbreviations: Undan-1 (e.g., U-1) and Bayu-2 (e.g., B-2).


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FIGURE 2 – Depth map at the top of the Aptian Unconformity (Early Cretaceous Darwin Formation)in the AC/P8 and AC/P16 study area showing SHmax stress orientation. The inward-facing arrows correspond to the direction of the maximum principal horizontal stress

(SHmax) inferred from wellbore failure in the respective wells.


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FIGURE 3 – Example of FMI image data from Laminaria-2 showing tensile wall fractures, as

indicated by their highly conductive nature (dark colour).


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FIGURE 4 - Example of STAR image data from Ludmilla-1 showing wellbore breakouts as indicated by the vertical dark regions of the

borehole. Sinusoidal feature on the amplitude and travel-time images are natural fractures.


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FIGURE 5 – Example of STAR image data from Lameroo-1 showing wellbore breakouts as indicated

by the dark vertical regions of the borehole.


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FIGURE 6 – a) Rose diagram and b) associated histogram showing the regional SHmax stress direction based on all stress indicators seen in thewells analysed in the AC/P8 area. Over 500 m of cumulative wellbore failure suggests that the regional SHmax stress directions is

150± 6

0 N. c) Rose diagram and d) associated histogram showing the regional SHmax stress direction based on all stress indicators

seen in the wells analysed in the AC/P16 area. Over 450 m of cumulative wellbore failure suggests that the regional SHmax stress

directions is 630± 6

0 N.


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FIGURE 7 – Profile of stress magnitudes inferred from data collected in the AC/P8 (and AC/L5 LaminariaArea). The pore pressure gradient is 1.03 SG. Minimum horizontal stress (Shmin)measurements are considerably less than the vertical stress (Sv). The vertical stress is based on

integration of the density log. The Shmin gradient, represented by the dashed line is primarilyconstrained by the most robust data types (e.g., LOT and XLOT). Results indicate that theAC/P8 area is associated with a strike-slip stress regime (SHmax>Sv>Shmin). Wellabbreviations: Alaria-1 (A-1), Vidalia-1 (V-1), Halimeda-1 (H-1), Corallina-1 (CR-1), Claudea-

1 (CL-1), Laminaria-2 (L-2) and Laminaria-5 (L-5).


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FIGURE 8 – Profile of stress magnitudes inferred from data collected in AC/P16. The pore pressure gradient i1.03 SG above 3000 m and 1.04 SG bellow 3000 m, based on well completion reports. FIT andLOT indicate that the minimum horizontal stress (Shmin) measurements are considerably less

than the vertical stress (Sv). The vertical stress is based on integration of the density log. TheShmin gradient, represented by dashed line in primarily constrained by the most robust datatypes (e.g., LOT) which actually propagated an hydraulic fracture away from the borehole. Theranges of the maximum horizontal stress (SHmax) were calculated based on the style ofwellbore failure seen in image logs in each respective well. Results indicate that the AC/P16area is associated with a strike-slip stress regime (SHmax > Sv > Shmin). Well abbreviations:Banka Banka-1 (BB-1), Fannie Bay-1 (FB-1), Lameroo-1 (L-1), Kittiwake-1 (KW-1), Jarrah-1

(J-1), Kellper-1 (K-1), and Fulica-1 (F-1).


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FIGURE 9 – Stress state for the Claudea-1 well at a depth of 2,900 mTVD. No wellbore breakouts wereobserved but tensile wall fractures were detected. The presence of tensile failures requires

that the stress state lines above the blue lines. Shmin values, determined from the XLOT performed in the Claudea-1 well at 2750 MD and LOT performed in nearby wells (Figure4), restrict the allowable range of SHmax magnitudes to between 71.2 and 86.8 Mpa. The

lack of breakouts requires that UCS > 95 Mpa.


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FIGURE 10 – Predicted wellbore breakout (BO) to constrain SHmax that is consistent with the observeddrilling-induced wellbore breakouts at 3926 mTVD in the Lameroo-1 well. The borehole cross-section a) shows the effective borehole circumferential stress distribution. The results oforward modelling an ‘unwrapped’ view of a borehole image for b) compressive failure and c)

tensile wall failure is consistent with the observed failure seen in Lameroo-1.


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FIGURE 11 – Calculated stress state resolved on a) the southwest trap-bounding fault and b) the northwest trap- bounding fault for the Corallina Field. These structural fault surfaces, based on 3D seismic data,were defined as individual elements or polygons. Far left plot shows the principal stress and pore pressure model. The natural fractures are indicated in three different styles: tadpoles (second fromleft; lower hemisphere stereographic projection; and 3D Mohr diagram including the Coulomb

frictional failure line corresponding to coefficient of friction (µ=0.6). The red and white dots

represent the critically-stressed elements of the fault plane.


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FIGURE 12 – Calculated stress state resolved on structural faults based on 3D seismic data in the Lameroo area. Figure description

same as Figure 11.


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FIGURE 13 – A 3D perspective view of the Corallina Field in AC/P8 (AC/L5) area, looking to thenortheast, showing the top of the Laminaria Formation and the major structural faultsmapped from 3D seismic data, defined as a series of connected faults segments. The CFFassociated with each of the faults is contoured as a fault attribute based on the orientationof the individual fault element with respect to the stress tensor derived from this study(stress direction and absolute stress magnitudes). The dark red contours correspond to

positive CFF (unstable), while orange-green to green corresponds to negative CFF(stable). Also shown is the approximate location of the current and palaeo-oil-watercontact inferred from GOI analysis. This corresponds to where segments of the fault become critically-stressed and therefore, less likely to behave as an adequate fault seal

for trap integrity.


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FIGURE 14 – A 3D perspective view of the Fannie Bay and Lameroo structures looking to thesouthwest, showing the top of the Laminaria Formation and the major structuralfaults inferred from 3D seismic data, defined as a series of connected faultssegments. Figure description same as Figure 13. The primary fault that definesthe Fannie Bay structure is critically-stressed for shear failure and therefore, less

likely to behave as an adequate fault seal for trap integrity. If only the uppersections of the primary fault surface adjacent to the Lameroo structure (withinthe cap rock) is critically-stressed, slip along this segment may propagate

downward into the reservoir.


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FIGURE 15 – A 3D perspective view of a) the Mallee Terrace in central AC/P16, looking to the southwest,showing the top of the Nancar Sands and the major structural faults mapped from 3D seismic data,defined as a series of connected fault segments. The Nancar-1, Ludmilla-1 and Mindil-1 wells areindicated as near vertical red lines. The grey to purple contours corresponds to critically-stressed

segments (CFF ≥ 0), while contour gradations from yellow, green to blue correspond to stablesegments (CFF < 0). B) Close-up view of the Ludmilla-1 area showing the approximate location othe palaeo-oil-water-contact inferred from GOI analysis in Ludmilla-1. Note that this is also thelocation at which sections of the fault become critically-stressed for shear failure and therefore,

less likely to behave as an adequate fault seal for trap integrity.


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FIGURE 16 – A Close-up 3D perspective view of the Mindil-1 area, looking to the west, showing the top othe Nancar Sands and the major structural faults inferred from 3D seismic data, defined as aseries of connected faults elements. The Mindil-1 well is indicated as a near vertical red line.The CFF contouring as for Figure 15. The ENE-WSW trending high-angle fault bounding thereservoir to the north (right side of plot) is critically-stressed and has a high probability of faultleakage due to shear failure. The ESE-WNW trending high-angle fault bounding the reservoir

to the south is at the threshold of failure due to fault slip.

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