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    IPA10-G-005

    PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATIONThirty-Fourth Annual Convention & Exhibition, May 2010

    THE KUJUNG FORMATION IN KURNIA-1 : A VIABLE FRACTURED RESERVOIR PLAY IN

    THE SOUTH MADURA BLOCKTrevor Magee*Craig Buchan**

    Jeremy Prosser**

    ABSTRACT

    The Kurnia-1 well was drilled as the first test of theKujung Formation in the South Madura exploration

    block on Madura Island in the East Java Basin. Thewell was drilled to test a large anticlinal structuremapped on 2D seismic data. The well encounteredvery strong mudlog gas shows that persistedthroughout the Kujung section. An open-hole

    production test flowed hydrocarbons to surface, butmechanical problems caused the test to beabandoned without determining a flow rate. Evaluation of wireline and Logging While Drilling(LWD) logs and sidewall cores from Kurnia-1indicated that the Kujung Formation carbonates arecharacterised by low matrix porosity; however,

    borehole resistivity and azimuthal density imagesreveal a high degree of fracturing, raising the possibility of a fractured reservoir play. Theobjective of this study was to evaluate the viabilityof a fractured reservoir. Mudlog, LWD and wirelinelogging data and borehole image log analysis wereintegrated in order to indentify and characterisefractures in the Kujung carbonates based on theirorientation and image characteristics. The study hasconfirmed strong fracture density in the KujungFormation and that zones of greatest fractureintensity also had the strongest gas shows. Fractures

    have been assigned to three orientations and thesefracture sets have been integrated into a coherentstructural framework. In the absence of productiondata, a qualitative assessment of permeability

    potential has been made based on fracturecharacteristics and orientation relative to local andregional structures. The results of the study indicatethe Kujung Formation in the South Madura block isa potentially viable fractured reservoir.

    INTRODUCTIONDeep water pelagic carbonates are commonthroughout South East Asia and particularly in

    * Cooper Energy** Task Geoscience

    Indonesia. Many of these formations are known tohost hydrocarbons, but the fine grained nature ofthe carbonates results in generally poor reservoirmatrix properties (Wilson 2002; Park et al. 1995).However, as a result of the active tectonic history ofthe region, many of these carbonates haveexperienced periods of faulting and folding,resulting in well developed fracture networks thatenhance their permeability and increase theireconomic potential. Similar fractured carbonatereservoirs are present in many large producingfields world-wide such as in Iran, Oman andCanada (e.g. Stephenson et al. 2007; Wennberg etal. 2007; De Keijzer et al. 2007; Rawnsley et al.2007). The Oligo-Miocene Kujung Formation ofthe East Java Basin (Figure 1) is an Indonesian

    carbonate in which reservoir characteristics may beenhanced by fracturing. This study focuses on datafrom a single well, Kurnia-1, located near the southcoast of Madura Island (Figure 1). The well wasdrilled through a Miocene clastic section to the

    primary objective Kujung Formation (Figure 1).Drilling proved difficult through the mid section ofthe well and into the lower carbonate dominatedsection and associated testing difficulties precludeda definitive production test, although hydrocarbonswere recovered to surface and several strong gasshows were recorded while drilling.

    In the absence of definitive production tests, adetailed analysis of open hole logs and geologicalinterpretation of Extended Range Micro Imager(XRMI of Halliburton) and Azimuthal Density(AZD of Weatherford) borehole image data wascarried out to assess the reservoir potential of theKujung Formation. The results reveal significantfracture populations in the Kujung Formation thatcoincide with the strongest gas shows. In addition,

    borehole image derived dip data suggests that thelarge scale structure is consistent with the currentstress field and that fractures have orientationsconducive to flow within this model. Based on thisevidence, it will be demonstrated that, despite the

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    apparent limited lithological potential of the KujungFormation, secondary porosity and permeability

    provided by the fracture networks mean that theKujung Formation may be a viable hydrocarbonreservoir. Moreover, the study will show thatcertain fracture orientations are more conducive toflow, demonstrating the need to properlycharacterise the orientation and nature of fracturesin order to fully exploit their potential.

    GEOLOGICAL SETTING

    Tectonic history and stratigraphy

    The tectonic evolution of the East Java Basin has been primarily controlled by the convergence of theIndo-Australian and Eurasian plates. The basin is

    situated on the southern margin of the stable SundaCraton to the north of a volcanic arc, runningthrough the centre of the island of Java. Itexperienced a complex tectonic history with initialextension followed by periods of differentialsubsidence and later inversion (Hamilton, 1979).The structural grain of the basin was controlled bythe fabric of the underlying basement. To thenorthwest of Madura Island in the Muriah Trough,Bawean Arch and Central Deep, this is

    predominantly NE-SW, whereas in the KendengTrough (onshore East Java) and the Madura Trough

    the orientation is E-W (Figure 1; Sribudiyani et al.,2005).

    The stratigraphy of the East Java Basin reflects a balance between carbonate and clastic deposition,governed by the relative influences of tectonics, sealevel and land-derived clastic input (Sharaf et al.,2005). Many different stratigraphic schemes have

    been employed by different companies in the EastJava basin. This paper has adopted the schemeemployed by Shell during their exploration ofMadura Island between 1988 and 9992. Thisstratigraphic scheme is shown in Figure 1; othercommonly used nomenclature may also be quotedin brackets.

    From the Early - Middle Eocene to Early Oligocenea tensional regime, traditionally associated with

    back-arc spreading, resulted in development of aseries of generally NE-SW ridges and grabensalong the southeastern margin of the Sunda shield.In the eastern part of the basin the trend is E-W.These grabens filled with a thick sequence of pre-

    Ngimbang and Ngimbang Formation clastics,including lacustrine shales that constitute the

    principal source rock in the region. In the ensuingsag phase, a fully marine shale sequence developed

    through the Late Eocene to Early Oligocene, withlocalised carbonate build up, referred to as the CDCarbonate. Renewed uplift ended this depositional

    phase and resulted in widespread erosion.

    Basin sag, traditionally associated with a slowing ofthe northward migration of the Australian plate inthe early Oligocene (Hall, 2002) or due to newlyinvoked northward subduction (Seubert andSulistianingsih, 2008), resulted in deposition of athick Oligocene section. This sag phase wasfollowed by a tectonically quiescent period fromLate Oligocene to Early Miocene times, duringwhich Kujung carbonate deposition was prevalenton stable land-attached platform areas and on fault-controlled seafloor highs, while shales and marlsaccumulated in basinal areas. In the Early Miocene

    rapid carbonate deposition was restricted to seafloorhighs where reef growth could keep pace with therapidly rising sea level. In the South Madura areaseafloor highs, such as the CD Ridge, are orientated

    parallel with the E-W structural grain. By midMiocene basinal shales and occasional thinturbidites of the Tuban (or Lower OK) Formationhad replaced carbonate deposition.

    A southward shift of the Australian plate boundaryin the Middle Miocene was followed by a phase ofwidespread magmatic activity across Java. The

    latest and most pronounced phase of compression began in the Mid Miocene: the main compressive phase commenced in the Late Miocene andcontinued episodically through to the present day.Pre-existing graben faults were reactivated resultingin large inversion structures. The North MaduraPlatform remained a relatively stable high, and was

    bounded to the south by the inverted former basinalregion, now Madura Island. The main structuralgrain over Madura Island at this time was East-West as reflected by the Madura Uplift Zone. Thesouthern part of Madura Island to the south of theMadura Uplift Zone remained basinal withdeposition of the marine siltstones and claystonesof the Tawun Formation intercalated withoccasional mass flow sandstones of the NgrayongMember. The Tawun Formation is overlain bysandstones and carbonates of the Bulu Formation oflatest Middle Miocene age. The Bulu Formation isoverlain by the Late Miocene Pasean (orWonocolo) Formation, which consists of a basalshale unit overlain by sandstones and limestones.This unit outcrops or has been eroded over much ofthe South Madura Block. The Pliocene Mundu andPaciran (or Kawengan) Formations are largelyeroded over the South Madura Block as is thePleistocene Lidah (or Pamekasan) Formation.

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    STUDY DATA

    The data integrated during this study was wideranging and included a regional seismic grid and a

    broad suite of downhole reservoir evaluation toolsrun across the Kujung Formation in Kurnia-1.These reservoir evaluation tools comprised: mudlogdata (lithology, gas, drilling parameters andformation pressure); LWD (gamma ray, resistivity,neutron and density logs) and wireline logs (duallaterolog, density, neutron, spectral gamma ray, fullwaveform sonic, formation pressure and dip imagelogs). Micropalaeontological analyses of cuttingsand sidewall core samples provided age dating anddepositional setting, while thin sections fromsidewall cores provided information on rock fabricand texture and qualitative assessment of porosity

    and permeability.

    In addition to the more standard suite of wirelinetools, borehole image logs were collected,

    providing a unique perspective on the geologicalevaluation of the Kujung Formation, becausestructural, lithological and petrophysicalinformation can be acquired at a much higherspatial resolution than standard open hole loggingtools. Adverse borehole conditions in some sectionsof Kurnia-1 meant that image logs were restrictedto two sections with a large (919 m) separation. The

    upper interval was logged over 1237.5 to 2086 mthrough the largely clastic Tawun and Tubanformations. The lower image interval was loggedover 3005 to 3350 m in the Kujung carbonates with

    both AZD and XRMI logs available. Image logs in both intervals were found to be of generally verygood quality with only minor stick and pullartefacts and some reduced image quality in regionswhere the borehole is enlarged.

    KUJUNG FORMATION MATRIXCHARACTERISATION

    The Kujung Formation comprises micro-crystalline packstone to wackestone with very poor visible porosity (Figure 2). In the upper part of theformation (3004-3052 m) the carbonates areintercalated with soft, silty claystones, with a highlyinterbedded nature as revealed by wireline logs.Log evaluation shows the limestones to begenerally tight with matrix porosities typically 3-6% with occasional beds with porosities of 8-10%.

    The lower interval from 3050 to 3350m was loggedusing LWD gamma ray, resistivity and density-neutron. This section was also logged with crossdipole sonic and XRMI wireline logs. These logs

    were merged with the available wireline logs run to produce a final suite of logs for interpretation of theentire Kujung section. A massive 250 metre thickcarbonate, becoming shalier towards the base, wasencountered between 3064-3313m. Matrix porosityin this thick carbonate section is low, averaging 4-6%.

    Drill Stem Test of Fractured Intervals

    Despite the overall tight matrix conditions, strongmudlog gas was encountered while drilling throughthe Kujung Formation and fluorescent shows werealso observed in these limestones in both cuttingsand sidewall cores. The strongest gas showsappeared to correspond to intervals of high fracturedensity as observed in the borehole image logs

    (XRMI) leading to a hypothesis that fractures werethe primary source of reservoir porosity in the tightcarbonates. A production test was run across theentire Kujung open-hole section to test hydrocarbondeliverability. The test was conducted as an open-hole test to avoid potential damage to the fracturenetwork that may have resulted from cementingcasing. Combustible hydrocarbons were detected atsurface, but mechanical problems caused the test to

    be abandoned without determining a flow rate. Thetest was aborted due to plugging of the test string

    by intraformational shales.

    STRUCTURAL CHARACTER OF THEKURNIA PROSPECT

    Seismic interpretation

    The Kurnia prospect was interpreted from seismicdata and regional structural information as a largewrench-related anticline with two structuralculminations (Figure 3). The structure wasdelineated on a 1.2 km x 1.8 km seismic gridcomprising data acquired in 1983, 1984, 1986 and1989. Although reprocessed using moderntechnology and workflows, data quality remains

    poor to fair. Figure 4 is a seismic line over theKurnia structure.

    The location of the structure close to the southerncoast of Madura Island, restricted seismic coverageover the crest of the Kurnia structure to a series ofline ends (Figure 3). Migration artefacts associatedwith these line-ends, have introduced someuncertainty into the interpretation of the top Kujunghorizon. However, despite these issues, the Kurniastructure was mapped as a robust four-way dipclosure, with several faults interpreted within thestructure, including a significant down-to-the-south

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    reverse fault immediately south of the Kurnia-1location (Figure 4). Interpretation of offshore linesconfirmed closure to the south, resulting in an arealclosure of approximately 130 km 2 with verticalrelief in the order of 400 ms TWT or 600 metres.Kurnia-1 was located to test the higher and betterdefined western culmination of the large-scale fold(Figure 3).

    Kurnia-1 borehole image analysis of large-scalestructure

    Although the main focus of this study is the KujungFormation carbonates, bedding dip data wasderived by manual picking of features in the XRMIimages from both the Tawun/Tuban and Kujungimage intervals in order to derive a large-scale

    structural model. The observed dip of beddingfeatures in the upper and lower image intervals isstrikingly different. The clastics of the upperinterval have a variable dip orientation but aregenerally shallow (40) to the NNE(Figure 5). The steep dips observed in the lowersection were unexpected based on seismicinterpretation, but are corroborated by AZD imageanalysis over the same interval as the lower XRMIimage.

    Despite the large data gap between the upper andlower image intervals (2086-3005 m), therelationships apparent when the data are viewed asa whole appear to confirm the large-scale foldgeometry suggested by the seismic analysis withsome additional complexities (Figure 5). Asillustrated in the dip azimuth vector plot of Figure5, there is a near continuous anti-clockwise azimuthrotation from the NNE to WSW. This isaccompanied by a gradual decrease in dip from

    base to top of the well, albeit punctuated by some probable fault modifications between around 1740m and 1850 m in the upper image interval (Figure5). Taken together these trends are consistent withthe strata from Kurnia-1 forming a large-scale NEverging antiform (Figure 6). The orientation of thisfold was tested by plotting all data on a stereoplotthat shows that the bedding forms a linear girdleconsistent with limbs of a fold with a calculatedaxis plunging shallowly WNW (Figure 5). Thisorientation was confirmed by plotting the data onan azimuth/depth histogram which shows a clear U-shaped profile (Figure 5).

    In addition to overall bedding trends, several faultswere interpreted to intersect the wellbore either by

    direct detection in the XRMI image, or frominterpretation of bedding trends. The majority offaults appear to have a WNW-ESE strike, parallelto the regional fold axis, but a few were alsointerpreted to strike in a more E-W direction andmay reflect basement trends (Sribudiyani et al.,2005).

    The overall fold geometry described by bedding issimilar to that interpreted from seismic of anantiform with a WNW-ESE axis, although the NNEvergence of the fold based on well data is notapparent from seismic interpretation. A number offactors may contribute to this apparent discrepancy:the seismic data over the Kurnia structure consist ofa series of line ends, resulting in poor imaging andmigration; the structural dips measured in the well

    cannot be accurately imaged on seismic; and thesteep NNE dips may be associated with dragrotation close to the down-to-the-NNE reverse faultsome 300 m to the NNE of Kurnia-1. It should also

    be noted that there is about 100 metres uncertaintyin the seismic line location. In addition the NNEvergent closure evident from well data may be arelatively minor reverse structure, resulting in anoverall box-fold geometry, which is not evident atseismic scale. The important factor is that both datasets confirm the overall orientation of fold and faulttrends.

    Drilling induced features and in-situ stress

    Drilling induced tensile fractures (DITF) wereobserved in both the upper and lower imageintervals of Kurnia-1. Orientation of features in theXRMI images showed that DITFs dominantly strike

    NNE-SSW (Figure 7). Breakouts were lesscommon in both intervals and are generally lowconfidence picks as the observed hole enlargementwas often coincident with local concentrations ofnatural fractures, making it difficult to rule out hole

    enlargement by washout of fractured material. Theinterpreted breakouts, although of low confidence,do generally plot as expected at 90 to DITF strike(Figure 7). The orientation of the DITFs indicatesthat SH max is orientated NNE-SSW and Sh min WNW-ESE, consistent with the overall large-scalefold geometry and suggests that the stress regimeobserved today may be long-lived.

    The concentration of DITFs is greater in the KujungFormation than in the upper clastic section. Whilstthis may be partially controlled by lithological

    properties, there is also a strong correlation withdrilling mud weight: the DITF frequency is highestwhere mud weight was highest, i.e. 16.5 ppg

    between 3080-3114 m (Figure 10).

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    CHARACTERISTICS OF FRACTURES INTHE KUJUNG FORMATION

    Fractures are common in the carbonates of theKujung Formation and are easily recognised in theXRMI images collected in the lower interval ofKurnia-1. Fractures were classified primarily asresistive or conductive relative to their hostlithology (e.g. Figure 8). In the case of conductivefractures, some show partial sinusoid traces on the

    borehole image that are similar to DITFs (Figure 8).The image trace tends to be strongest in the portionof the image that corresponds to the tensile failuredirection (as determined from the occurrence ofDITFs) and diminishes away from this point(Figure 8). Previous studies have documentedsimilar features elsewhere and suggest that the

    coincidence of these features with the DITForientation and their incomplete image trace arecaused by the fractures being drilling enhanced andopened in response to borehole hoop stresses(Barton and Zoback, 2002; Barton et al., 2009). Inview of this fact these fractures were classifiedseparately as drilling enhanced features.

    The imaged fractures are variable in orientation, butcan be divided into three groups based on strikeorientation (Figure 9): group 1 strikes dominantly

    NNE-SSW, group 2 strikes N-S and group 3 NW-

    SE. Conductive fractures are more common thanresistive (Figure 9), but this may be related to thedominance of resistive calcareous lithologies in theKujung Formation making resistive fractures moredifficult to detect. No clear crosscutting relationshipwas observed where one set of fractures is offset byanother. Accordingly the temporal relationship ofthe different strike groups cannot be determined.

    The fractures were further characterised bycalculating spacing and density parametersspecifically: orthogonal spacing of fractures in eachset; cluster thickness; un-fractured matrix thickness;and along hole fracture and fracture cluster density.Summary statistics for each of these parameters are

    provided in Tables 1 and 2 and discussed brieflyhere. Calculated spacing statistics for individualfractures indicate that fractures in all threeorientation groups are on average closely spaced(Table 1). Minimum spacing is around 1 cm and themajority of fractures have spacing of less than 15cm. The full range of spacing values is variable upto a maximum of around 50 m for NW-SE strikingfractures. Spacing statistics for all three groupshave a lognormal distribution with spacing valuesheavily skewed towards small spacing in eachgroup, indicating that the fractures are strongly

    clustered, a conclusion that it is reflected in thefracture density distribution (Figure 10). To testthese conclusions, the orthogonal width of fractureclusters was determined and the spacing of clustersin each group calculated in order to fullycharacterise fracture distribution (Table 1).

    Figure 10 shows the approximate distribution offracture clusters for each fracture group and Table 2shows statistics for the cluster density (number offractures within a cluster). These data show that the

    NNE-SSW striking fractures have the largestnumber of fractures per cluster (maximum 37 and amean of around 4), although this is closely matched

    by N-S striking fractures, which have a meancluster density of around 3 fractures per cluster anda larger total number of clusters at 77. The NW-SE

    striking fractures have a mean of less than 2fractures per cluster and a median of 1, highlightingthe isolated nature of fractures in this orientation.However, it should be noted that the mode for eachgroup is one fracture indicating that isolatedfractures are common in each group (Table 2).

    Fracture aperture assessment

    The calculation of fracture aperture values from borehole resistivity images is complex. Severalmethods have been suggested in different studies

    based on measurement of excess conductance overthe fracture interval. The most common algorithmused was devised by Luthi and Southait (1990)and has many limitations that are discussed in detail

    by the authors. The most important issue for thecurrent study is that the method is considered to beinvalid for fractures with > 40 dip, which is thecase for all fractures in the Kujung study interval.To test this effect, the algorithm was used acrossthe lower image section of Kurnia-1, but was foundto generate patently unrealistic apertures of >5 m.Based on these results the method was consideredto be inappropriate for the study well.

    As an alternative, a method was used in which theinterval of excess conductance associated with thefracture is measured and a pixel distance derivedfrom the image that is equivalent to the fractureheight calculated by Luthi and Southait (1990).The method is cruder than that of Luthi andSouthait (1990), but is effective in giving aqualitative estimate of average fracture aperture. Asummary of the derived apertures is provided inTable 3.

    Based on visual examination of the XRMI images,it is unlikely that any of the fractures have apertures

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    greater than 1 cm, and the apertures determinedusing the excess conductance technique appear to

    provide reasonable results for the majority of thefractures measured with a median calculatedaperture of 1 cm and mode and mean of 3 mm. Ifthe effects of apparent versus true thickness (due toangle of intersection of the fracture with thewellbore) are taken into consideration, then it ismore likely that the true fracture aperture is on themillimetre rather than centimetre scale. The verylarge calculated apertures of as much as 51.5 m aregenerated where the algorithm detects moreconductive responses from adjacent carbonatemudstone beds and interprets these as a fractureresponse. These excessively large apertures areclearly erroneous and should be ignored.

    VIABILITY OF THE KUJUNG AS AFRACTURED RESERVOIR

    The viability of a fractured reservoir depends on thefractures being open and connected. In Kurnia-1 thefirst qualitative indication of an open fracturenetwork was obtained when the well repeatedlykicked when drilling through the upper Kujungsection, and the associated gas had to be circulatedout through the choke manifold while themudweight was increased. A production test was

    performed in an attempt to quantify the production potential from the fractured Kujung reservoir: thisflowed combustible hydrocarbons to surface, buttesting difficulties prevented the flow test from

    being completed conclusively.

    In the absence of conclusive test results, qualitative predictions of flow potential have been made basedon the image log characteristics of the fractures andtheir orientation relative to present day stress and/orknown larger scale structures. In the followingsections the character and orientations of thefractures in the Kujung Formation are considered inan attempt to qualitatively rank fracture orientationswith respect to their potential for fluid flow.

    It is very difficult to assess the openness andconnectivity of a fracture network based purely onwireline logs and borehole image logs. It is oftenassumed, when drilling with conductive water

    based muds, that conductive fractures are open because they give a mud response. However, aconductive response would also be obtained fromclosed fractures filled with conductivemineralisation such as pyrite or shale gouge.Conversely, resistive fractures suggest cementationand yet may transmit fluid.

    Relationship of fractures to large-scale structure

    As outlined, there is strong evidence from beddingdip trends from Kurnia-1 to support the case thatthe strata form a large-scale anticlinal structure(Figures 5 and 6). Asymmetric folds of this type arecommon in the over-riding plate in fold and thrust

    belt settings at subduction boundaries as is the casefor Madura Island. Seismic interpretation of theKurnia structure suggests that folding is faultcontrolled in the form of a forced fold (Cosgroveand Ameen, 2005) with folding induced in theoverlying strata as the fault progressively breaksthrough from below.

    The mechanical nature of such folds has beenstudied in great detail and the fracture patterns

    expected in these features can be readily predicted based on the variance of outer arc extension andinner arc compression around the fold hinge (e.g.Price 1966; Stearns 1978; Cosgrove and Ameen2005). Based on the method of Price (1966) atheoretical fracture orientation set was generated tocompare to the fractures observed in Kurnia-1 inorder to assess whether the fracture orientation setscould be generated purely from folding (Figure 11).In this theoretical scenario the upper clastic sectionwould sit on the gently SW dipping limb and thelower image interval, Kujung Formation, would fall

    on the steeply dipping NE limb (Figure 11). It canthen be demonstrated that the theoretical fracture

    patterns depicted in Figure 11 closely match all ofthe defined sets observed in Kurnia-1. In addition,the model predicts that the tensional (T) fractures,which form parallel and perpendicular to the foldhinge, will be orientated normal to bedding.Therefore, the T1 and T3 fractures, formed parallelto the hinge, should dip in the opposite direction to

    bedding in each of the fold limbs and show reversedip on either side of the fold limb (Figure 11). Thisis indeed the case for Kurnia-1: in the upper imageinterval (on the SW dipping limb) bedding dips

    broadly to the W or SW whilst the hinge-parallelfractures dip to the NE; and in the lower imageKujung interval beds dip to the NNE whilst hinge-

    parallel fractures dip to the SW (Figure 11).

    An additional feature of forced folds observed intype examples such as the Zagros Mountains of Iran(e.g. Satterzadeh et al. 2000; Stephenson et al.2007), is that they tend to form periclinal or doubly

    plunging non-cylindrical folds, which can causeenhancement of the fractures that strike

    perpendicular to the main fold hinge (T2 and T4 inFigure 11). This could explain the preponderance of

    NNE striking fractures observed in both of the

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    To convert these estimates into permeability potential it is inherent that assumptions are madethat all of the fractures are open to fluids (i.e. arenot cemented or filled with gouge) and areconnected away from the wellbore and have infiniteextension along their length. If this were the casethen NNE-SSW striking fractures alone would

    provide reasonable permeability potential and ifconnected to either of the other groups then

    potential for flow is good.

    Fracture occurrence compared to mudlog gasshows

    All of the discussions presented suggest that there isindeed very good potential for the fracture sets inthe Kujung Formation to form a viable hydrocarbon

    reservoir. However, all of these methods are in oneway or other indirect tests of flow potential. Despitethe problems encountered during productiontesting, it is very encouraging that combustiblehydrocarbons flowed to surface, although it is notclear that these were sourced from the fracturedintervals. In this regard the record of mudlog gas

    proves extremely valuable in demonstrating that theextracted gas is most likely sourced from thefractured intervals. Figure 10 shows fracturedensity and cluster occurrence for each fracture set

    plotted alongside mudlog gas. This plot highlights

    that there is a direct correlation between fractureoccurrence and high mudlog gas levels. In additionthe mudlog gas is highest over intervals of NNE-SSW and N-S striking fractures, confirming

    predictions that fractures within 30 of SH max aremore likely to be open to flow. However, gas showsdo not seem to correlate with the occurrence ofDITFs: the interval of greatest DITFs (3080 to 3115m) has very low mudlog gas (Figure 10). This isencouraging as it suggests that whilst some naturalfractures may be enhanced during drilling, they areopen anyway and not required to be held openunder mud pressure to produce gas.

    SUMMARY

    Based on the data outlined in this study, it has beenshown that, despite poor primary matrix porosityand permeability in the carbonates of the KujungFormation, fractures within the formation appear tohave the necessary porosity and permeability tohost and produce hydrocarbons. The fracturesappear to have formed subject to a consistent long-lived stress field and are optimally orientated withrespect to present day in-situ stress to be open tofluid flow. There is extremely good correlation

    between the occurrence of observed gas shows

    during drilling and the distribution of fractures inthe well, and an incomplete drill stem test showedthat it was possible to produce combustible gas tosurface. All of these features combine to suggestthat the Kujung Formation is indeed a viablefractured hydrocarbon reservoir.

    Information gathered on the nature of the fracturenetwork will be useful in well design for futureappraisal and exploitation of the fractured Kujungreservoir. The structural model can be used to

    predict zones of most intense fracturing. Productionwells should be drilled as horizontal or highlydeviated wells in a northwesterly orientation inzones of greatest predicted fracture intensity tomaximise the intersection of open fractures. Furthergeomechanical studies should also be performed to

    optimise mudweight to control formation pressurewhile avoiding invasion and damage of fracturenetwork.

    ACKNOWLEDGEMENTS

    The authors wish to thank the management andgeotechnical staff of Cooper Energy and our jointventure partners in the South Madura PSC, NationsPetroleum and PT Eksindo for their support andencouragement to conduct this study and to draftthis paper and to MIGAS for their permission to

    publish this paper.

    REFERENCES

    Barton, C.A., D. A. Castillo, D. Moos, P. Peska,M.D. Zoback, 1998, Characterizing the full stresstensor based on observations of drilling-inducedwellbore failures in vertical and inclined boreholesleading to improved wellbore stability and

    permeability prediction, APPEA Journal 1998, 29-53.

    Cosgrove, J. W. and Ameen, M. S., 2005. Acomparison of the geometry, spatial organisationand fracture patterns associated with forced foldsand buckle folds. In: COSGROVE, J. W. &AMEEN, M. S. (eds.), Forced Folds and Fractures.Special Publication of the Geological Society,London, 169, 7-21.

    De Keijzer, M., Hillgartner, H., Al Dhahab, S. andRawnsley, K., 2007. A surface-subsurface study ofreservoir-scale fracture heterogeneities inCretaceous carbonates, North Oman. In: Lonergan,L., Jolly, R. J. H., Rawnsley, K. and Sanderson, D.J. (eds.), Fractured reservoirs. Special Publicationof the Geological Society, London, 270, 227-244.

    http://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdfhttp://www.geomi.com/publications/10-CharacterizingFullStressTensorAPPEA.pdf
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    http://www.sciencedirect.com.dbgw.lis.curtin.edu.au/science?_ob=ArticleURL&_udi=B6V6X-44HWS3W-2&_user=41361&_coverDate=03%2F15%2F2002&_alid=1215016903&_rdoc=2&_fmt=high&_orig=search&_cdi=5826&_sort=r&_docanchor=&view=c&_ct=15&_acct=C000004498&_version=1&_urlVersion=0&_userid=41361&md5=b07e0ee7c8766ce7816e82181047eda0http://www.sciencedirect.com.dbgw.lis.curtin.edu.au/science?_ob=ArticleURL&_udi=B6V6X-44HWS3W-2&_user=41361&_coverDate=03%2F15%2F2002&_alid=1215016903&_rdoc=2&_fmt=high&_orig=search&_cdi=5826&_sort=r&_docanchor=&view=c&_ct=15&_acct=C000004498&_version=1&_urlVersion=0&_userid=41361&md5=b07e0ee7c8766ce7816e82181047eda0http://www.sciencedirect.com.dbgw.lis.curtin.edu.au/science?_ob=ArticleURL&_udi=B6V6X-44HWS3W-2&_user=41361&_coverDate=03%2F15%2F2002&_alid=1215016903&_rdoc=2&_fmt=high&_orig=search&_cdi=5826&_sort=r&_docanchor=&view=c&_ct=15&_acct=C000004498&_version=1&_urlVersion=0&_userid=41361&md5=b07e0ee7c8766ce7816e82181047eda0http://www.sciencedirect.com.dbgw.lis.curtin.edu.au/science?_ob=ArticleURL&_udi=B6V6X-44HWS3W-2&_user=41361&_coverDate=03%2F15%2F2002&_alid=1215016903&_rdoc=2&_fmt=high&_orig=search&_cdi=5826&_sort=r&_docanchor=&view=c&_ct=15&_acct=C000004498&_version=1&_urlVersion=0&_userid=41361&md5=b07e0ee7c8766ce7816e82181047eda0http://www.sciencedirect.com.dbgw.lis.curtin.edu.au/science?_ob=ArticleURL&_udi=B6V6X-44HWS3W-2&_user=41361&_coverDate=03%2F15%2F2002&_alid=1215016903&_rdoc=2&_fmt=high&_orig=search&_cdi=5826&_sort=r&_docanchor=&view=c&_ct=15&_acct=C000004498&_version=1&_urlVersion=0&_userid=41361&md5=b07e0ee7c8766ce7816e82181047eda0http://www.sciencedirect.com.dbgw.lis.curtin.edu.au/science?_ob=ArticleURL&_udi=B6V6X-44HWS3W-2&_user=41361&_coverDate=03%2F15%2F2002&_alid=1215016903&_rdoc=2&_fmt=high&_orig=search&_cdi=5826&_sort=r&_docanchor=&view=c&_ct=15&_acct=C000004498&_version=1&_urlVersion=0&_userid=41361&md5=b07e0ee7c8766ce7816e82181047eda0http://www.sciencedirect.com.dbgw.lis.curtin.edu.au/science?_ob=ArticleURL&_udi=B6V6X-44HWS3W-2&_user=41361&_coverDate=03%2F15%2F2002&_alid=1215016903&_rdoc=2&_fmt=high&_orig=search&_cdi=5826&_sort=r&_docanchor=&view=c&_ct=15&_acct=C000004498&_version=1&_urlVersion=0&_userid=41361&md5=b07e0ee7c8766ce7816e82181047eda0
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    TABLE 1 - SUMMARY STATISTICS OF FRACTURE SPACING

    Individual fracture spacings Cluster width Matrix block widthGroup

    orientation60/118

    56/270

    45/211

    60/118

    56/270

    45/211

    60/118

    56/270

    45/211

    Count 345 314 86 50 77 42 50 77 42Min

    Spacing(m) 0.013 0.008 0.013 0.072 0.090 0.070 0.558 0.149 0.163Max

    Spacing(m) 35.433 36.548 53.126 3.086 2.030 1.013 35.350 36.420 30.830

    GeometricMean (m) 0.164 0.270 0.329 0.485 0.493 0.161 2.294 1.559 1.671

    Median (m) 0.115 0.197 0.231 0.565 0.507 0.116 2.231 1.507 1.269Mode (m) 0.060 0.088 0.047 0.087 0.135 0.082 0.565 0.807 N/A

    St Dev 2.497 2.439 6.588 0.848 0.561 0.231 5.559 4.444 6.820Err or W 0.012 0.011 0.020 0.012 0.011 0.020 0.012 0.011 0.020

    Acute angle 34.790 32.179 48.795 34.790 32.179 48.795 34.790 32.179 48.795Kurtosis 115.834 149.200 43.798 0.455 -0.294 2.540 21.405 44.957 6.807

    Skewness 9.453 10.793 6.121 1.187 0.852 1.756 4.180 6.130 2.627

    TABLE 2 - SUMMARY STATISTICS OF CLUSTER DENSITY FOR EACH ORIENTATION GROUP

    Grouporientation 60/118 56/270 45/211

    Number ofclusters 50 77 42

    Min number offractures 1.000 1.000 1.000

    Max number offractures 37.000 15.000 15.000

    Mean 3.860 2.997 1.604Median 4.000 3.000 1.000Mode 1.000 1.000 1.000

    St Dev 7.973 3.223 2.352Kurtosis 4.30 2.033 21.81

    Skewness 2.08 1.526 4.23

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    TABLE 3 - SUMMARY OF CALCULATED FRACTURE APERTURES

    statistics - all fracturesnumber offractures 633.000

    Min aperture (m) 0.003Max aperture (m) 51.506

    Mean aperture(m) 0.003

    Median aperture(m) 0.010

    Mode 0.003St Dev 2.685

    Kurtosis 220.717Skewness 13.168

    TABLE 4 - SUMMARY OF FRACTURE POROSITY ESTIMATES

    UnitsGroup 1 -60/118

    Group 2 -56/270

    Group 3 -45/211

    Mean cluster separation m 2.294 1.559 1.671Mean cluster width m 0.485 0.493 0.161

    Mean number of fractures 3.9 3.0 1.6

    Max number of fractures 37 15 15

    Mean fracture aperture m 0.003 0.003 0.003

    Effective aperture m 0.012 0.009 0.005

    Effective Max aperture m 0.111 0.045 0.045Porosity estimate from cluster

    width % 17.4 24.0 8.8

    Porosity estimate fromfracture aperture and mean

    number of fractures% 0.5 0.6 0.3

    Maximum Porosity fromaperture and max number of

    fractures in cluster

    % 4.6 2.8 2.6

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    Figure 1 - (a) Map of the East Java Basin showing dominant tectonic trends reflecting the dominantinfluence of subduction along the Java Trench. Location of the study well Kurnia-1 is alsoshown on the south coast of Madura Island. (b) General stratigraphic column for the East JavaBasin, note that stratigraphic unit names in this area are not standardised and the nomenclatureof Shell is adopted here for convenience.

    Figure 2 - Photomicrographs of thin sections taken from sidewall cores in the Kujung Formation, showingtypical matrix characteristics of the carbonates.

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    Figure 3 - Seismic depth map of top Kujung horizon. The Kurnia structure is characterised as a doubly plunging anticline with a dominant NW-SE axis. The positions of two reverse faults controllingformation of the structure are shown in relation to the collar position of Kurnia-1.

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    Figure 4 - SW-NE Seismic line showing location of Kurnia-1 relative to reverse faults.

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    Figure 5 - Combined vector azimuth walkout plot, stereonet and dip azimuth/depth plot of all bedding inthe Kurnia-1 image intervals. Note that there is a data gap from 2086-3005 m between theintervals. The vector walkout plot indicates a near continuous anticlockwise azimuth rotationfrom NNE dip to SW dip from base to top of section. This relationship is further confirmed bythe stereoplot which shows a well defined elongate girdle indicative of a cylindrical fold feature

    and the azimuth/depth plot which shows a clear U-shaped distribution. The calculated fold axisis 8/286 from the stereoplot and 10/285 from dip/azimuth. Vector walkout plot created usingTask Geoscience Attitude software, dip/azimuth plot created using Quickdip software.

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    Figure 6 - Comparison of bedding fabric orientations in XRMI and ALD imagery. Both image typesconfirm steep NNE dipping bedding in the Kujung Carbonate section. Figure 6 - Possible foldgeometry for strata in Kurnia-1 incorporating imaged NW-SE trending faults from seismicinterpretation. In this scenario it is interpreted that steep NNE dipping beds in the KujungFormation are formed by frictional drag along the red reverse fault. The SW dips that aredominant in the seismic interpretation on the south limb of the structure are formed bymovement across the blue fault. Well dip projection to section line created using TaskGeoscience Attitude software.

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    Figure 7 - Examples of DITFs from lower image interval in Kujung Carbonate section. Left image showstypical DITF forming two conductive stripes 180 apart in XRMI imagery. Note that AZDresponse appears largely unaffected. DITFs appear to be offset along natural fracture traces andnatural fractures may be enhanced at points of intersection. In right image DITFs can be seen to

    branch into so called petals. Note that DITFs appears bed bound in this case. Rose diagramsshow DITF and breakout orientations for features picked in the upper and lower image intervalsof Kurnia-1: these dominantly indicate a NE-SW orientation for SH max and NW-SE orientationfor Sh min.

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    Figure 8 - Examples of image characteristics of fractures in the Kujung Formation. Note scale variesslightly in each image.

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    Figure 10 - Log plot showing a comparison of fracture density distribution, as raw density (black) andcorrected for borehole sampling bias (red); fracture cluster occurrence per group; DITFdensity and mudlog gas. The comparison indicates that the gas shows all occurred at fracturedintervals and most commonly where fractures strike N-S or NNE-SSW. There appears to bean almost negative correlation with DITF occurrence: where DITFs are most numerousmudlog gas is low.

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    Figure 11 - (a) Predicted orientation of fractures within the limbs and hinge of an asymmetric forced fold(after Price 1966; Cosgrove and Ameen 2005). Fractures labelled T are tensional while Rfractures are shear fractures. (b) Example of predicted fracture orientations adapted for adoubly plunging periclinal fold geometry (after Stearns 1978). Note that the R or shearfractures (red and green) change orientation around the outer flanks of the dome (right ofimage) reflecting the change in orientation caused by the periclinal folding and tending to

    parallelism with the T fractures (magenta) that form along the main hinge line. (c) Correlationof predicted fracture patterns with those observed in Kurnia-1. The correlation fit is very goodwith all of the predicted fracture orientations observed in the well data.

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    Figure 12 - Simple plane strain ellipse for the Kurnia structure illustrating expected shear displacementsunder NE-SW orientated maximum compressive stress. Rose plot shows a qualitative

    prediction of fractures that may be under critical stress and therefore more likely to be open tofluid flow.

    Figure 13 - Summary of methods used to calculate fracture porosity.