BALEIA-1 Well Evaluation Report

5/21/2018 BALEIA-1 Well Evaluation Report

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Timor Sea Block JPDA 06Timor Sea Block JPDA 06--102102

BALEIABALEIA--11WELL EVALUATION REPORTWELL EVALUATION REPORT

ByBy

Timor Sea Exploration TeamTimor Sea Exploration TeamJULY 2010JULY 2010


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BALEIA-1 WELL EVALUATION REPORT, BLOCK JPDA 06-102, OFFSHORE TIMOR-LESTE

CONFIDENTIAL, JULY2010 PAGE2OF29

TABLE OF CONTENTS

TABLE OF CONTENTS ..

LIST OF FIGURES ..

LIST OF TABLES .

LIST OF APPENDIXES...

LIST OF ENCLOSURES.....

1.0 EXECUTIVE SUMMARY...

2.0 PRE-DRILL SUMMARY.

3.0 POST-DRILL SUMMARY..

4.0 GEOPHYSICS DISCUSSION ..

4.1 SEISMIC DATA..

4.2 DATA QUALITY.

4.3 WELL DATA

4.4 WELL-TO-SEISMIC CORRELATION.

4.5 SEISMIC INTERPRETATION

4.6 TIME TO DEPTH CONVERSION.

4.7 ATTRIBUTE ANALYSIS.

5.0 GEOLOGICAL EVALUATION..

5.1 REGIONAL SETTING...

5.1.1 BASIN TECTONIC HISTORY ...

5.1.2 STRUCTURAL HISTORY OF NORTHERN BONAPARTE BASIN .

6.0 PETROLEUM SYSTEM

6.1 PETROLEUM SYSTEM SUMMARY .....

6.2 SEAL ......

6.3 TRAP...

6.4 HYDROCARBON SOURCE.....

6.5 SOURCE ROCK POTENTIAL..

6.6 MATURITY AND HYDROCARBON GENERATION..

6.7 MIGRATION AND TIMING

7.0 RESERVOIR EVALUATION..

7.1 CALLOVIAN ELANG FORMATION..

7.2 BATHONIAN-BAJOCIAN PLOVER FORMATION..

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8.0 G & G SPECIALIZED STUDY..

9.0 HYDROCARBON RESOURCE ASSESSMENT .......

9.1 PETROPHYISICAL ANALYSIS...

9.2 RISKING ON PETROLEUM SYSTEM...9.2.1 SOURCE ROCK....

9.2.2 RESERVOIR...

9.2.3 TRAP

9.2.4 MIGRATION

10.0 CONCLUSIONS........


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LIST OF FIGURES

FIGURE 1.1: LOCATION OF THE BALEIA - 1

FIGURE 1.2: BALEIA-1 DRILLING PROGRAM PLAN VERSUS ACTUALFIGURE 1.3: BALEIA-1 LOGGING PROGRAM

FIGURE 1.4: BALEIA-1 TOP FORMATION DEPTH PROGNOSIS VERSUS ACTUAL

DEPTH

FIGURE 4.1: BLOCK JPDA 06-102, 2D AND 3D SEISMIC DATABASE MAP

FIGURE 4.2: SYNTHETIC SEISMOGRAM OF BALEIA-1 WELL

FIGURE 4.3: MAKIKIT -1 SYNTHETIC SEISMOGRAM

FIGURE 4.4: MAKIKIT-1 AVO SYNTHETIC SEISMOGRAM

FIGURE 4.5: MAKIKIT-1 VSP GEOGRAMFIGURE 4.6: TOP OF ELANG POST-DRILL DEPTH STRUCTURE MAP

FIGURE 4.7: INLINE 2301 THROUGH BALEIA-1 WELL

FIGURE 4.8: INLINE 2301 THROUGH BALEIA-1 WELL (ZOOM-IN)

FIGURE 4.9: CROSSLINE 3784 THROUGH BALEIA-1 WELL

FIGURE 4.10: CROSSLINE 3784 THROUGH BALEIA-1 WELL (ZOOM-IN)

FIGURE 4.11: RANDOM LINE THROUGH MAKIKIT-1 AND BALEIA-1 WELL

FIGURE 4.12: MAKIKIT-1 VERSUS BALEIA-1 TIME/DEPTH CURVE

FIGURE 5.1: STRATIGRAPHIC SUMMARY OF THE BONAPARTE BASINFIGURE 5.2: TECTONIC ELEMENTS OF THE BONAPARTE BASIN

FIGURE 6.1: BALEIA-1 POST-DRILL CORRELATION

FIGURE 6.2: HORIZON FLATTENING AT MAKIKIT-BALEIA STRUCTURE

FIGURE 6.3: POSSIBLE HYDROCARBON MIGRATION PATH

FIGURE 6.4: FLUID INCLUSION STRATIGRAPHY (FIS) RESULTS (MAKIKIT-1)

FIGURE 6.5: KEROGEN TYPE AND MATURITY PROFILE FOR MAKIKIT-1

FIGURE 6.6: SOURCE ROCK IN FLAMINGO AND ELANG/PLOVER FORMATIONS

(MAKIKIT-1)

FIGURE 6.7: POST-DRILL PRESENT-DAY MATURITY MAP AND HYDROCARBON

GENERATION PHASE MAP AT TOP PLOVER FORMATION (SOURCEROCK)

FIGURE 6.8: JPDA 06-102 POST-DRILL TIMING OF OIL AND GAS EXPULSION CHARTS

FIGURE 6.9: BALEIA-1 PETROPHYSICAL LOGS ANALYSIS RESULTS

FIGURE 6.10: BALEIA-1 ELANG FORMATION SAMPLE CUTTINGS DESCRIPTION

FIGURE 6.11: BALEIA-1 ELANG FORMATION WATER SAMPLE


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FIGURE 6.12: MAKIKIT-1 ELANG FORMATION PETROGRAPHIC ANALYSIS

FIGURE 6.13: MAKIKIT-1 PLOVER FORMATION PETROGRAPHIC ANALYSIS

LIST OF TABLES

TABLE 4.1: LIST OF HORIZONS INTERPRETED

TABLE 9.2: PETROHYSICAL PARAMETRES FOR GAS CASE AT ELANG/PLOVER

FORMATION

APPENDIXES

APPENDIX 1: BALEIA-1 SIDE WALL CORE DESCRIPTION

APPENDIX 2: PETROPHYSICAL EVALUATION REPORT

ENCLOSURES

ENCLOSURE: TOP ELANG RESERVOIR DEPTH STRUCTURE MAP (1:25,000 SCALE)


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1.0 EXECUTIVE SUMMARY

Baleia-1 well was a vertical exploration well drilled in Block JPDA 06-102, BonaparteBasin, offshore Timor-Leste. It is the last of the three commitment wells drilled in BlockJPDA 06-102, Timor-Leste. The wells surface location is in water depth of 78.6 m, and

is approximately 1.6 kilometres east of Makikit-1, 14.3 kilometres northeast of Bayu-4,17.5 kilometres northwest of Mistral-1, 18.6 kilometres east of Elang-1 and 42.6kilometres northwest of Fohn-1(Figure 1.1). MakikitBaleia Complex is situated about300 kilometres SW from Dili and 500 kilometres NW from Darwin Supply Base. The wellwas spudded on the 9th March 2010 using the Ocean Shield jack-up rig.

The main objective for Baleia-1 is to revisit the Makikit-Baleia Complex due to theinconclusive result of Makikit-1 well drilled in the same structure. This Baleia-1 well isproposed to re-evaluate the Makikit-Baleia Complex since Makikit-1 well logs analysisindicate presence of hydrocarbons in the Callovian Elang/Plover clastic sequencesbelow the Flamingo Formation. This target has been tested in the Makikit-1 well but dueto the borehole condition problem, most of the acquired data were not conclusive

enough to confirm the status of the well.

The wells location and trajectory (Figure 1.2) was purposely designed to explore thehydrocarbon potential of the fault bounded 3-way dip closure Makikit-Baleia Structure. Theresults of the regional tectonic study, combined with well information from offset wells andseismic interpretation were incorporated into Baleia-1 final well drilling program.

Baleia-1 well was drilled vertically from the seabed (78.6m MDDF) and successfully setthe 20 casing and 13 3/8 casing at 715.6 m TVDDF (716m MDDF) and 2182.7mTVDDF (2184m MDDF).

The HC shows had been indicated from the cuttings while drilling in the targeted reservoir

section from depth 3276 3355 m MDDF. The gamma ray and resistivity wireline loggingresults indicated the presence of hydrocarbons in the reservoir objectives at the depth3276 to 3355 m MDDF. However, only three (3) valid pressures data was acquired out ofthirty (30) points attempted from depth interval 3286.8 - 3318 m MDDF within the targetedreservoir section. These valid pressure points have indicated the presence of water belowthe HC indicative reservoir.

MDT Dual Packer has been applied for the fluid sampling and acquired a sample fromdepth 3286.6 m MDDF. The analysis indicated the sample as formation water withcontamination of mud filtrate. The salinity measured ranged between 41,000 to 44,000mg/l and 5.2 to 5.7% of NaCl.

Sidewall cores (CST) were taken in the reservoir section from depth 3273m MDDF to3411m MDDF and the detail was shown in Appendix 1. No production test was carriedout from this well. The planned and the actual of Baleia-1 logging program and formationtops are shown inFigure 1.3 and Figure 1.4.

Baleia-1 was plugged and abandoned with gas show on 24 April 2010.


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2.0 PRE-DRILL SUMMARY

OPERATOR PC (TIMOR SEA 06-102) LTD.

WELL NAME / TYPE BALEIA-1/EXPLORATIONBLOCK BLOCK JPDA 06-102, OFFSHORE TIMOR-LESTE

WELL OBJECTIVESThe objectives are to explore the hydrocarbon potential ofElang/Plover Formation Sandstone

RESOURCES (STOIIP/GIIP/CIIP)BEST ESTIMATE

Elang/Plover - Callovian sandstone: TOIIP 22 MMSTB(P50)

OFFSET WELLS

Makikit-1 ( 1.6kilometres West), Mistral-1 (17.5 kilometresSSE), Bayu-4 (14.3 kilometres SW), Elang-1 (18.6kilometres W), Elang-3 (16 kilometres W), Fohn-1 ( 42.6

kilometres SE)DISTANCE TO BASE/ FACILITY Approx. 500m from Darwin, Australia

WATER DEPTH 77.0 metres

PROPOSEDLOCATIONS

SURFACE LOCATION:SEISMIC LINE : INTERSECTION OF 3D SEISMIC LINES:INLINE 2301 AND CROSSLINE 3784

Latitude: 10 54' 1.694"SLongtitude: 126 45' 26.593"E

Y: 8,794,118m NX: 254,868m E

PROPOSEDTD 3,500m TVDss (+/-100 metres)

RIG& DRILLINGCONTRACTOR Ocean Shield/ Diamond L.L.C

ESTIMATED WELLCOST USD44.7 Million

Dry Hole : USD38 Million

ESTIMATED SPUDDATE February 2010


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3.0 POST-DRILL SUMMARY

WELL STATUS P&A with gas show

SPUD DATE 9 March 2010 @ 21:30hrs

PLUG AND ABANDONED 24 April 2010

RIG / TYPE / DFE Ocean Shield / Jack-up

LOCATION

Latitude : 10 54' 01.714" SLongitude : 126 45' 26.617" ENorthing : 8 794 117.39 mEasting : 254 868.73 m

ACTUAL TOTAL DEPTH 3414.6 m TVDDF/ 3376.22m TVDSS

DATE TD REACHED 9 April 2010 at 20:45 hrs

OTAL DAY TO WELLCOMPLETION

47 days

ACTUAL WELL COST USD 39 Million

WATER DEPTH 78.6 metres

TOP OF MARKERS

TOPFORMATION

DEPTH

m MDDF m TVDDF m TVDSS

Seabed 117.0 78.6 40.2Oliver 691.0 690.6 652.2Hibernia 738.0 737.6 699.2Johnson 1548.0 1546.9 1508.5Vee 2044.0 2042.8 2004.4Wangaralu 2470.0 2468.6 2430.2

Darwin 2987.0 2985.2 2946.8Echuca Shoals 3030.0 3028.1 2989.7Flamingo 3082.0 3080.0 3298.3Elang 3273.0 3270.8 3232.7Plover 3339.0 3336.7 3298.6TD 3417.0 3414.6 3376.2


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4.0 GEOPHYSICS DISCUSSION

4.1 SEISMIC DATA

The JPDA 06-102 area is covered by 2D and 3D seismic data (Figure 4.1). The

interpretations of the 2D seismic lines cover the northern and middle part of the BlockJPDA 06-102. The 2D seismic interpretation identified all the available leads within theblock and determines which leads are prospective enough to continue with more detailstudy by acquiring 3D seismic. The proposed 3D seismic data covers the Makikit-Baleia,Paus and Tubaraun structures.

The 3D seismic data was acquired by the CGGVeritas vessel MV Orion that towed sixstreamers with a separation of 100 metres giving a total width of 500 metres. The activelength of streamers is 6 km long, towed at a depth of 6 metres and consist of 480channels. The energy source was comprised of two 2,940 cubic inch air guns, towedastern of the vessel, separated at 50 metres between ideal centers and at a depth of 5metres. The sources were fired in a flip-flop mode with alternate 2,940 cubic inch arrays; a

7.0 second record length with 18.75 metres pop interval (37.5 metres shotpoint interval)was used giving a coverage fold of 80. The acquired data was processed atWesternGecos processing centre in Kuala Lumpur. The processed 3D seismic data wasdelivered to PCTSL in mid June 2008.

The Makikit-Baleia structure was interpreted on both 3D and 2D seismic data. The 2Dseismic data interpretation was merged with the acquired 3D seismic data to better imagethe west flank of Makikit-Baleia structure.

4.2 DATAQUALITY

The 3D seismic data quality is generally fair to good. The shallow carbonate sections

within the JPDA were the main cause for the data deterioration which leads to significantsignal loss at reservoir level.

4.3 WELL DATA

The well information was obtained mainly from the Baleia-1 well and Makikit-1 well whichlocated approximately 1.6 km to the West of Baleia-1. The well data from both wells werecalibrated and used as references for re-mapping the Post Drill map over the Makikit-Baleia structure.

4.4 WELL-TO-SEISMIC CORRELATION

Main well to seismic tie was obtained from the Synthetic Seismogram of Makikit-1 well.The top of Elang sand (Base Flamingo Unconformity) of Baleia-1 well is situated at thecasing shoe (Figure 4.2) and the well did not have any VSP run for comparison.Therefore, the main synthetic seismogram used for the Makikit-Baleia structure wouldstill be the one generated from Makikit-1 well logs (Figure 4.3).

The seismic 3D lines were processed with a PCSB standard normal polarity but it wasloaded into the workstation as a reverse polarity dataset. Based on the syntheticgenerated the increase in impedance of the top of Elang sand (Base Flamingo


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Unconformity) falls on a black peak (Figure 4.3 and 4.4). This was further supportedby the Makikit-1 VSP Geogram (Figure 4.5).

4.5 SEISMIC INTERPRETATION

The Makikit-Baleia structure was interpreted on both 2D and 3D seismic data. The Elangformation was interpreted on the 3D data as a black peak. The Makikit-Baleia structurewas interpreted using 3D data on every 10 In-line and 10 Cross-line spacing to define thefault and structure.

Interpretation from 2D and 3D seismic data was merged to give a better delineation of theElang East and Makikit-Baleia structures. Interpretation of the Elang Formation shows thatboth Elang East and Makikit-Baleia structures are located on the same West-East trendingnormal fault block and were separated by a saddle between them (Figure 4.6).

Generally, 8 horizons representing the different ages were mapped on 2D seismic data(Figure 4.7, 4.8, 4.9, 4.10 and 4.11).The Intra-Triassic and Base Permian horizons were

not interpretable on most seismic lines due to poor seismic data resolution. Table 4.1below shows the main interpreted horizons.

Table 4.1: List of horizons interpreted.

Schlumbergers PETREL software was utilized to carry out a standard interpretationworkflow, which is summarized below:1. Horizon picking2. Fault & horizon interpretation3. Gridding and Contouring4. Generating Two-Way-Time (TWT) maps.5. Generating depth structure maps.

Based on adjacent well and regional stratigraphic chart, the horizons picked on seismicdata represent the formation top listed on table above. However not all lithologicalchanges observed on well logs and cuttings are significant on seismic data due to theaverage seismic data quality and limitation on seismic data resolution.

Below listed the seismic characteristic of some of the reflector interpreted as the top of theFormation:

Base Eocene (Johnson Formation)The Paleocene Johnson Formation of dominantly contains interbedded argillaceouscalcilutites, marls and calcareous claystones. The significant reflector with strong peakamplitude represents the Johnson Fm. Top.

HORIZON AGE MA FORMATION SEISMIC EVENT

WATER BOTTOM PRESENT DAY TIMOR SEA TROUGHBASE EOCENE EOCENE 57 JOHNSON PEAK

TURONIAN MFS TURONIAN 91 WANGARLU TROUGHBASE APTIAN BASE APTIAN 123 ECHUCA SHOALS TROUGH

BASE FLAMINGO OXFORDIAN 157 ELANG PEAK


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CONFIDENTIAL, JULY2010 PAGE11 OF29

Turonian MFS (Wangarlu Formation)The Albian Wangarlu Formation is a claystone unit. The claystones are reasonablyconsistent over the unit, although begin to grade to siliceous claystone at the base. Thetop of Wangarlu Fm. is very significant on seismic data and was picked on the trough.

Base Aptian (Echuca Shoal Formation)The Barrimian Echuca Shoal Fm. overlies the Darwin Fm. represented mainly by clayeymaterials with occasionally traces of carbonaceous material.The significant reflector withstrong trough amplitude represents the top of Eucuha Shoal Fm. This reflector is easilycorrelated on the well to seismic and were used as seismic-well marker to determine theexpected reservoir top while drilling.

Base Flamingo (Elang Formation)Unconformably underlying the Flamingo is Callovian Elang Formation. Contained withinthis reservoir unit are beds of silty claystones, claystones, argillaceous and siltysandstones, argillaceous silt and sandy siltstone. Unlike the 2D data, top of Elang wasrepresented by a significant reflector in the 3D data. Based on the well data, Top of Elang

on 3D should be picked on the peak.

The most challenging step in the interpretation workflow was the fault and horizoninterpretation. The identified faults were checked in every adjacent 3D line to understandthe nature of the throw and each fault were defined as normal faults. Generally the faultsare observed as an east-west trending normal faults at the Baleia structure. Thedisplacement of the faults ranges between 100 to 400 metres.

4.6 TIME TO DEPTH CONVERSION

The poly equation derived from Makikit-1 T-Z curve is used in converting the time maps todepth. The Baleia-1 and Makikit-1 T-Z curves ties well at reservoir level. (Figure 4.12).

The formulation for T-D conversion used is:

Y = 0.00002x + 1.5766x (Figure 4.12)

Due to the poor quality of the 3D Seismic Stacking Velocity and the stability of the velocitywithin the Bonaparte Basin, no velocity model was generated for the depth conversion.

4.7 ATTRIBUTE ANALYSIS

Based on the AVO feasibility studies carried out in-house, Elang sands falls under theType 3 AVO sands which if hydrocarbon bearing will becomes dimmer with offset.

Attributes analysis have been attempted to chase this dim effect however no significanttrend can be deduced therefore was not shown in this report. This was due to low signalfrequency and some noises together with fair to poor data quality especially near thestructure location.


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5.0 GEOLOGICAL EVALUATION

5.1 REGIONAL SETTING

The Bonaparte Basin located predominantly offshore, covers approximately 270,000

square kilometres of Australias north continental margin. The basin contains up to 15kilometres of Phanerozoic, marine and fluvial, siliciclastic and carbonate sediments.

The basin had undergone two phases of Paleozoic extension, a Late Triassiccompressional event and further extension during the Mesozoic. Convergence of the

Australian and Eurasian plates in the Miocene to Pliocene resulted in flexural downwarp ofthe Timor Trough and widespread fault reactivation across the western Bonaparte Basin.The Summary of Geological Elements of Bonaparte Basin are shown in Figure 5.1

5.1.1 BASIN TECTONICS HISTORY

The Bonaparte Basin is structurally complex and comprises numbers of Palaeozoic and

Mesozoic sub-basins and platform areas.

The main depocentres of the Bonaparte Basin (Figure 5.2) occured within the offshorePetrel Sub-basin, its outboard extension, the Sahul Syncline and the Malita Graben, anorthogonal depocentre in the east of the Basin. The Bonaparte Basin is bounded to thesouth by the Darwin and Plover shelves. Long-lived platforms were located near theedge of the continental shelf; historically, these platforms (in particular the Sahul and

Ashmore Platforms) formed important uplifted blocks during the failed rift tectonic event.

Shuster, et al., 1998 defined the northern margin of the basin as the Timor Trough, wherewater depths exceed 3,000 metres. They included the Laminaria and Flamingo (Bayu-Undan) Highs; the Flamingo Syncline, which separated the Sahul Platform from the

Flamingo High; the Sahul Platform, and its regional constituents, the Kelp andTroubadour Highs, and separating these the Sikatan Trough, a low which bisects theplatform.

The Bonaparte Basin history dated from the Early Palaeozoic. The pre-Permian historyof the JPDA was speculative as sediments of that age had been deeply buried andtherefore have not been penetrated. Late Devonian to Early Carboniferous northewest-southeast crustal extension created the onshore Petrel Sub-basin. This sub-basin had asimilar orientation to that of the Sahul Syncline in the JPDA area and both wereinterpreted to be formed as a result of the same tectonic movements. A period ofnortheast-southwest crustal extension at the very Late Carboniferous-Early Permianinitiated widespread deposition throughout the basins of the North West Shelf (Longley,

et al., 2002), creating the Malita Graben, located to the south of the JPDA.

The Bonaparte Basin geometry remained much the same for a large portion of theTriassic. Uplift at the southern margin of the Basin took place during the Norian-Carnian(Fitzroy Movements). Structural movement during this stage included an element ofnorth-south compression, rifting of micro-continents to the northwest of the BonaparteBasin and thermal doming (Longley, et al., 2002). The Flamingo High was formed andthe Sahul Platform and Ashmore Platform were uplifted during this time, creating awidespread disconformity with the Early Jurassic sediments deposited after the Fitzroy


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Movements had ceased (Whittam, et al., 1996). The main period of continental marginrifting commenced during the Callovian, prior to the fragmentation of easternGondwanaland and the failure development of Jurassic rift system through the mainbasin of the North West Shelf (Longley, et al., 2002, Jablonski and Saittta, 2004). TheCallovian unconformity (JC) is the result of movement in the early stages of this event

and exhibits only weak angularity in the JPDA. North-south and northeast-southwestcrustal extension during the Callovian-Oxfordian led to further rifting in the MalitaGraben, Sahul Syncline, and Nancar Trough (Shuster, et al., 1998, Whittam, et al., 1996and Longley, et al., 2002).

Rifting due to crustal extension continued throughout the Early Oxfordian and wasexpressed with mild angularity in some parts of the study area. North-south extensionduring the Kimmeridgian-Berriasian advanced the rifting process, especially in theLaminaria High-Nancar Trough-Sahul Syncline area, with fault blocks in that regionundergoing their main period of uplifting during this time.

The separation of Greater India from eastern Gondwana during the Valanginian

corresponded to the completion of the rifting / rift-infill stage in the basins of the NorthWest Shelf and the onset of thermal decay of the margin during the post-rift stage(Longley, et al., 2002 and Jablonski and Saitta, 2004). Marine influences increased anddepositional energies were generally lower. The northern Bonaparte Basin remained arestricted depocentre until the Late Aptian when India separated completely fromGondwana and oceanic circulation increased. Thermal decay of the edge of thecontinental plate and the opening Indian Ocean resulted in the Formation of a passivecontinental margin setting (Longley, et al., 2002).

The Australian continental plate separated from Antarctica during the Cenomanian andcommenced its relative northern motion (Longley et al., 2002), trending to the NorthNorth West. In the Late Eocene the Australian Plates motion shifted to North North East

(Shuster et al., 1998). In the Late Oligocene Early Miocene the Australian plate collidedwith the Banda rch. Partial subduction of the Australian plate (Berry and McDougall,1986 in Shuster et al., 1998) and uplift of Sumba island occurred approximately 8 Ma(Keep et al 2002, Longley et al 2002) caused by the continued oblique left-lateralcollision of the Australian and Eurasian plates. This tectonic episode created a proto-foreland basin in the Timor Trough and brought about strong flexural subsidence at theedge of the shelf re-activated pull apart rifting in the Cartier Trough in the Vulcan Grabenand the Malita Graben south of the JPDA area (Shuster, et al., 1998). Approximately 3-4million years ago Timor Island collided with the Banda Arch (eg Simandjuntak andBaber, 1996, Longley et al., 2002) resulting in the jamming of the subduction zone in thatlocation, the uplift of Timor Island and subsidence of the Timor Trough (Longley et al.,2002, Keep et al etc). The Australian Plate continued to move north with a shift of

subduction north to the Flores and Wetar thrust zone which are noted to be tectonicallyactive today (Shuster et al., 1998, Longley et al., 2002). The blocking of the subductionzone by continental crust in the area of Timor resulted in differential stress compared tothe unblocked area of the Australian Plate to the east of this zone, which furtheraccentuated the shear stress in the area. This northward movement is easier in thesection of the Australian Plate that lies to the east of the Timor Trough jammed zone,accentuating the left lateral wrench related faulting within the area (Shuster et al., 1998).The relative plate motion continues to the present day at a rate of some 7.5-8cm/year(Shuster, et al., 1998).Thus reactivation of faults in the study area during the neogene


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has occurred under varring stress regimes, including the tensional stress related toflexure of the plate as it was subducted and the changing shear stress and left lateralwrenching related to the Australian Plates differential oblique northern motion (Shusteret al., 1998 and Keep et al., 2002).

5.1.2 STRUCTURAL HISTORY OF NORTHERN BONARPARTE BASIN

The Northern Bonaparte Basin structural style consists of Late Jurassic to earliestCretacaeous synrift fault structures that had usually formed above pre-existing structuralfeatures and had undergone some Cretaceous and Neogene re-activation under anoblique, left-lateral, strongly strike-slip domain. As well as Miocene to present day,extensional faulting with a significant strike-slip component associated with the Timortrough to the North and the Malita Graben to the South (Shuster et al., 1998, Keep et al.,2003).

The pre existing structural features which focus subsequent tectonic structuring are thecoherent basement blocks of the Sahul Shelf, the Laminaria and Kelp High, which are

surrounded by basins with northeast to southwest and northwest to southeast trends.Rift related faulting during the Late Jurassic to Early Cretaceous had created a set ofeast to west trending faults and another northwest to southeast trending set (eg. Shusteret al.,1998). The northwest-southeast trending set was strongly developed in the MalitaGraben and the east-west trending set was strongly developed in the Sahul Syncline.Faults in the Sunrise Troubadour area trend east-west to eastnortheast-westsouthwest(Shuster et al., 1998).

Faults observed in the Miocene to Recent are dominantly northeast to southwest with aneast to west trending subset and a northwest southeast trending subset (Shuster et al.,1998). Studies of neogene fault styles in the area (eg Keep et al., 2003 and Shuster etal., 1998) conclude that the majority of faults occured along the margins of preexisting

structural highs. With those in the north of the study area, most of the faults stronglyinfluenced by plate flexure adjacent to the Timor Trough and those in the south of thearea were most strongly influenced by left lateral deFormation related to the reactivationof the Malita Trough.

The combination of these fault styles has created complex, multiple fault set geometries,frequently detached at shallow and deep levels that require high quality 3D data sets forsatisfactory resolution. Faults at the reservoir level are strongly east to west typical ofthe Nancar Trough and Laminaria High. In contrast faults in the shallow section shiftorientation to northeast-southwest at the Pliocene level. The linkage of the shallowfaulting and the deeper faulting is considered to be very important to trap integrity at themain target level of the Elang/Plover reservoir. It is believed that the fault connectivity is

controlled by the ductility and thickness of the upper Jurassic - Cretaceous claystoneswhich act as a ductile layer (Keep et al., 2003).


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6.0 PETROLEUM SYSTEM

6.1 PETROLEUM SYSTEM SUMMARY

There are four main petroleum systems recognized may have contributed as major

hydrocarbon source within the Block JPDA 06-102, Timor-Leste. The Permian gas isderived from the Petrel Sub-basin & Northern Bonaparte Basin and reservoired inPermian sediments as referred in Kelp Deep. Secondly the Triassic to Pre-rift Early toMid Jurassic Plover Formation oil and gas reservoired in the sediments of the PloverFormation as referred at Sunrise-Trobadour. The third is the Post-rift, Middle to UpperJurassic oils from a combined Plover and Elang Formation source reservoir in the ElangFormation sandstones as referred at Elang wells. Lastly, the Lower Cretaceous oilswhich probably sourced from the Echuca Shoals Formation.

The study area is bounded to the north and south by the Malita Trough and the SahulSyncline hydrocarbon kitchens. These depositional thicks provide the main sourcehydrocarbons for the surrounding reservoir units. Smaller features such as the Sikatan

Trough may also provide source hydrocarbons as evidenced by the results of Sikatan-1and Bard-1 wells where >30bbl of oil were recovered while drilling the FlamingoFormation. At Sikatan-1 well in the southern end of the Sikatan trough significanttransFormation of organic matter to oil has occurred. The main source rocks for the unitare the Plover, Elang and the Echuca Shoals Formations.

Expulsions of hydrocarbons begin about 65 million years ago in the Malita Graben andcontinue to this day. Expulsion in the Sahul syncline and the deepest part of theFlamingo Syncline commenced 35 million years ago. The maturation of the system wasinitially driven by the deposition of a thick pile of Upper Cretaceous sediments in thedepositional centers. With further drive created by the progradation of the carbonatewedge over the whole shelf edge during the Tertiary. Sediments within the eastern

Malita Graben are now over mature for oil, with gas expulsion from its flanks while in theSahul and Flamingo Synclines sediments lie in the oil window. This variation across thearea has given rise to two (2) distinct JPDA provinces. The Eastern Sahul Platform,which is characterized by large dry gas pools as referred east of the JPDA,gas/condensate fields in areas removed from the dry gas charge and possible oilexpulsion from the Sikatan trough (Bard-1 well oil kick on the western edge of theTroubadour field)

In contrast the Western Sahul Platform, Flamingo Syncline, Flamingo High and SahulSyncline is characterized by 50-62 API undersaturated oil and wet gas pools, mainly infault blocks at Elang/Plover Formation. Pools often partially filled with Plover-type oils.Darwin-type Lower Cretaceous oil charge characterized by 40 deg API, mainly in

Cretaceous fracture porosity showing little mixing with Plover-type dry gas at topPermian level on the Kelp High.

One of the distinct characteristics of the Timor Sea area is the relatively high percentageof partially filled or breached Jurassic oil columns. The current study done by Gartrell etal., 2006 has identified 8 wells within the Timor Sea area that either failed due to faultbreach or changes in the trap configuration, or they were discoveries but containedsignificantly less than the total trap capacity. This interpretation was based on therecognition of residual oil columns (visual oil staining or on logs), or Paleo-oil columns.


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At Bayu Undan locality it is shown that through time the shape and size of the closuremapped at the JC level has changed. These changes happened due to the effects of thechanging stress regime and consequent reactivation tipping and tilting of the existingstructures. Fault reactivation can result in the juxtaposition of possible theif zones, whichmay then result in cross fault leakage. Shuster et al. (1998) puts forward that in the

extreme case If the trap development or modification is dynamic, it is possible that thetrap could evolve from a valid Paleotrap to an invalid trap, due to cross fault juxtapositionor tilting and then be further modified to a structurally valid, but dry trap at the presentday. The other consequence is that tilting of a trap can give extremely large apparentpaleo-oil column heights that do not reflect the true size of the original trap. In spite ofthis potentially dynamic system, recharging of modified traps is likely to occur as long asthe trap lies proximal to a present-day source kitchen (Shuster et al., 1998).

The zones of highest reactivation risk are those zones that lie on or adjacent to shearzones in areas of the basin that are releasing bends as defined by the basementconfiguration. It is noted that the Western JPDA Neogene and Jurassic fault intensity ismuch greater than the Eastern JPDA. Faulting on the flanks of the Malita Graben and

the northern boundary of the Sahul Shelf are also currently active (e.g. Shuster et al.,1998 and Keep at al., 2003) see discussion of Basin Tectonic History above.

6.2 SEAL

The top seal is presented by 52 metres of Echuca Shoals and 191 metres of FlamingoFormations(Figure 6.1). Based on the Baleia-1s sample cutting description, the EchucaShoals is dominated by the claystone with some influence of carbonaceous material. TheFlamingo Formation which is deposited below the Echuca Shoals Formation is a siltstone,claystone and sandstone interbedding formation. The Makikit-Baleia structure located atthe up-thrown section of the fault and juxtaposed against the Flamingo Formation whichdominated with shale at the down-thrown section.

There are two possible routes for hydrocarbon to leak out from the reservoir which arefirstly through the lateral migration to Flamingo Formation and secondly along the faultplane to shallower zone(Figure 6.3).

The Flamingo Formation is dominated with claystone and interbedded with sandstone andsiltstone. The Baleia-1 well result indicates that the Echuca Shoals and FlamingoFormations are approximately 52 metres and 191 metres respectively. Therefore theElang/Plover Sandstone reservoir juxtaposed against the Flamingo Formation at thedownthrown side and possible for hydrocarbon to escape laterally to the Elang Structureor other shallower area. On the other hand, the Flamingo Formation dominated withclaystone may act as permeability barrier and limit the hydrocarbon escape laterally.

Therefore, the lateral migration is not dominant at the Makikit-Baleia structure whereas itsinterpreted that the hydrocarbon leakage along the fault zone is more preferable.

The combination of 240 metres top seal of these Echuca Shoals and Flamingo Formationsis proven present in Baleia-1 from the lithology descriptions and well logs interpretation.The effectiveness of the top seal is believed proven especially in the Echuca ShoalsFormation, since the formations consisted of low permeability materials. The Northwest-Southeast fault across the structure is believed to be not sealing and allowing themigration of hydrocarbon from the Elang/Plover to the shallower formation.


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6.3 TRAP

The trapping mechanism at Makikit-Baleia Structure is interpreted as a fault boundedthree (3) way dip closure. Based on the horizon flattening analysis, the structure wasformed earlier, before the hydrocarbon generation and expulsion (Figure 6.2). The

structure is bounded by a fault extending Northwest-Southeast direction to Elang Kakatuaoil field located at Northwest corner of Makikit-Baleia Structure. Based on the post-drillinterpretation, the highest displacement of the fault at the crestal is around 350 metres.

Based on the gas reading and the gas sample that encountered in the Baleia-1 well, thereare possibilities for the hydrocarbon trapped in Elang/Plover reservoir to breached andescaped to shallower Formations. In Bonaparte Basin, the Neogene extensional totranstensional tectonic reactivation affects most of the trap bounding faults and the majorcontributing factor for the leakage.

The well has encountered the increasing of gas reading up to nC5 since before reachingthe target zone, which is from 2993.0 metres in Darwin Formation until final TD. Besides,

the cut fluorescence was noted from depth 3276m to 3355m MDDF. The fault re-activationmay cause the hydrocarbon from Elang/Plover reservoir to escape along the fault toshallower formation.

6.4 HYDROCARBON SOURCE

Based on source rock evaluation on Northern Bonaparte Basin and nearest fields such asBayu Undan, Elang and Kakatua, there are three (3) potential source rocks; theElang/Plover land plant influence organic matters, Echuca Shoals marine-derived shaleand Flamingo group land plant influence organic matter (Figure 5.1).

Three (3) key wells Fohn-1, Minotaur-1 and Mistral-1 were studied to determine the

source rock composition within the Block JPDA 06-102. Observation from Elang/PloverFormations in-situ source shows a high TOC (2.95% wt) shale observed from inter-bedded shale between thick sand bodies. At Fohn-1 well, the shale are high maturitymainly with inertinite/bitumen. The Flamingo and Echuca Shoals Formations arepredominantly containing shale/claystone. The Flamingo shale have TOC rangingbetween 0.5 to 1.00 wt% but with poor organic matter quality except at Mistral-1 wellwhich probably due to the mixture between Type III and Type II/III.

The mid-Jurassic Plover Formation could contain terrestrial organic matters in the intra-Formational shale which may provide direct hydrocarbon charge into the overlyingsandstone reservoirs. Fair qualities of organic matter were noted in the late JurassicFlamingo group and early cretaceous Echuca Shoals Formations. The Echuca Shoals

source rocks contained more marine matter hence more oil prone. This, combined withvertical variations in the proportion of Type III organic matter, has resulted in thegeneration and expulsion of lighter oil and gas/condensate-like products from theElang/Plover source rocks, and more common marine-derived oils from Echuca ShoalsFormation.


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6.5 SOURCE ROCK POTENTIAL

The ditch cutting samples from Makikit-1 have undergone the Fluid Inclusion Stratigraphic(FIS) and photomicroscopy analysis. The FIS study involving the automated analysis of oiland gas components trapped as fluid inclusions (micron-sized, crystallographically

isolated cavities) in rock material. The results of the study had revealed rare to moderategravity oil inclusions at 750 and 1490m MDDF which are in Oliver and HiberniaFormations. The rare to common upper moderate gravity petroleum inclusions were foundat 3210m MDDF (Flamingo Formation), 3305m MDDF (Elang Formation) and 3405mMDDF (Plover Formation). The pictures and the details of the study are shown in Figure6.4. No visible petroleum inclusions found at 910, 2270, 2970, 3040 and 3450m MDDF.

The FIS analysis confirmed the presence of hydrocarbon at reservoir level at a moment oftime. The Makikit-Baleia complex has a proven source rock and hydrocarbon migrationpathway.

6.6 MATURITY AND HYDROCARBON GENERATION

Based on the geochemical analysis on sixty (60) ditch cutting samples from Makikit-1resulting that, the source rock in this well contained of poor to good (0.1 to 2.19 wt%)organic richness matter. The average of Hydrogen Index (HI) is within 100-300 and beenclassified as Type III kerogen (terrestrial depositional environment) source rock. From theanalysis result, the top oil window is at about 2000m MDDF. The detail of the kerogen typeand maturity are shown inFigure 6.5.

The Flamingo and Echuca Shoals Formations which are predominantly shale/claystonealso contained of high Total Organic Carbon (TOC), 0.45 to 1.10 wt% and high HI value(281 to 376), indicating the presence of good quality organic matters (Figure 6.6).

The intra-formational source rock sample within depth 3295m MDDF until TD inElang/Plover Formation was identified contained of rich and good quality organic matter(0.80 to1.60 wt%). The HI value for this formation is within 136 to 232 which indicating thepresence of type III kerogen (potential for gas and oil generation). The vitrinite reflectanceobserved (0.90 - 0.92%) was classified as mature for oil and gas generation (Figure 6.6).

Therefore, the occurrence of hydrocarbon charge for the Block JPDA 06-102 is valid.

6.7 MIGRATION AND TIMING

There are not much variation between pre-drill and the post-drill modeling parameters.The data obtained from drilled wells had either varies slightly or confirmed the predicted

value used in the pre-drill modeling.

The basal heat flow model has been calibrated with the heat flow values from Makikit-1(56 mW/m2) and Kurita-1 ST-1 (65 mW/m2) wells to generate the post-drill maturity mapfor Block JPDA 06-102. The post-drill basal heat flow result for Makikit-1 was found lowerthan the pre-drill estimation (65 mW/m2). There is no calibration for the area south ofKurita-1 ST-1, but the heat flow for this well is estimated much higher since it is toward tothe Malita Graben. The nearby Fohn-1 well heat flow is 63 mW/m2. The post-drill basalheat flow model is shown in Figure 6.7.


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Based on the present-day maturity at Top of Plover Formation generated, it is showingthat maturity of Block JPDA 06-102 is slightly high. The southeastern part of the Block iscurrently in Gas Generation Phase (Figure 6.7).

At the deepest part of the study area (PS-01 well), the oil expulsion had occurred in the

Late Cretaceous, which is much earlier than predicted in the pre-drill model. The gasexpulsion was found occurred since the Late Cretaceous until present-day. The pre-drillmodel predicted expulsion for the gas began in Early Tertiary. The detail of thehydrocarbon expulsion for the JPDA 06-102 is shown in Figure 6.8.

Even though the post-drill modeling results indicated hydrocarbon expulsion from theMalita Graben probably occurred much earlier, the shallower source rock (within the BlockJPDA 06-102) could still provide hydrocarbon charge to the traps. Therefore, thehydrocarbon charge is not the main risk for the existent of hydrocarbon accumulation inthis area.

7.0 RESERVOIR EVALUATION

Reservoir evaluation for Elang/Plover reservoirs which were penetrated by Baleia-1 wasconducted. Although the Elang/Plover is consider as a single system hydrocarbonaccumulation due to the ineffectiveness of inter-formational seals, the reservoirs is stillcan be differentiated based on their geological and petrophysical characteristics.

The factors that are believed to play the most significant role in determining the presentday reservoir porosity are the reservoir composition, texture and the fluid flow.

The reservoir composition and texture can contribute to significant role in determining thereservoir porosity. On the marco-scale, thin sandstones interbedded with claystone and

siltstones appear to be more prone to quartz cementation than thick massive sandstones.This matter is noticed in all the 3 wells drilled. The results from the Makikit-1 well sampleanalysis demonstrate that the significant amount of cementation has occurred at thereservoir level. The Porosity at Elang Formation is obviously lower compare to the deeperPlover Formation. Silica rich fluid migrating through the sandstones as a geochemicalfront precipitates silica as an envelope of quartz overgrowth development at thesandstone/ claystone interface at the top and base of the individual sandstones. In fact,thinner the sandstone, the envelope can fill the entire sandstone.

In addition to that, the presence of claystone in sandstone reservoir can cause a majorcompaction on the sandstone. Clay in the intergranular pore space is squeezed into theremaining pore space and clogs the pore throats as compaction progresses, reducing the

effective porosity and permeability.

The ditch cutting samples from Makikit-1 have been used for petrographic analysis toevaluate the characteristic of the reservoir in Makikit-Baleia Complex. Based on theanalysis showing that, the visible porosity is ranged from 1-5%. Pore types are generallyminor secondary dissolution porosity with lesser primary intergranular showing overallisolated to very poor interconnectivity. Reservoir quality generally ranges from poor tovery poor in these sandstone samples. The reduction of this reservoir quality is due to the


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quartz overgrowth, moderate compaction and localized ferroan dolomite and kaolinitecements.

MDT pressure test was done in the Elang/Plover Formation (3273m MDDF - 3417mMDDF). Only three valid pressure data out of thirty (30) points were acquired at the

depth of 3341m MDDF, 3343.2m MDDF, and 3349.4m MDDF. Twenty two (22) pointsencountered lost seal while two (2) points were tight and the other two (2) points weresupercharged. A sample was taken from the MDT dual packer at the depth of 3286.6mMDDF indicated that the formation water contaminated with mud filtrate was recovered.The detail on the MDT results is shown in Figure 6.9.

Thirty (30) shots of Core Sample Taker (CST) were logged for the well. Only twenty-two(22) bullets were recovered while other eight (8) were empty (Appendix 1). No DST wascarried out for the well as the reservoir is interpreted as tight with no moveablehydrocarbon column.

7.1 CALLOVIAN ELANG FORMATION (3273 3339 m MDDF)

The Elang Formation is unconformable underlying the Flamingo Formation. ThisFormation is believed deposited in deltaic environment.

Based on Baleia-1 sample cutting descriptions, Elang was described as interbedding ofclaystones, siltstones and sandstones dominated formation. The claystones weredescribed in cuttings as medium gray to dark gray, occasionally dark gray, soft to firm,occasionally sub-blocky and contained traces of carbonaceous materials and glauconites.The siltstones are described as olive black to brownish black, occasionally brownish gray,firm to hard, occasionally soft, sub-blocky to blocky, occasionally sub-platy, noncalcareous, and contained of traces of glauconites, and grading to very fine grains. Thesandstones major are transparent to translucent, off white to very light gray, very fine to

fine grains, sub-angular to sub-rounded, hard to very hard, moderate sorted, occasionallycalcareous cemented, contained traces of glauconites and had very poor visible porosity.

The Gamma ray log response showed the obvious trend of coarsening upward behavior.The resistivity log showed a little separation between the shallow resistivity and the deepresistivity log which indicate the change of fluids or materials contained by the lithologynear the borehole and formation. The density and porosity logs overall does not showgood indicator for hydrocarbon accommodation due to the high bulk density (average 2.75G/C3) and low neutron porosity (average 0.09 V/V) readings which gave the earlyindication of the tight formation (Figure 6.9).

Pale yellowish florescence cut were observed in cutting samples in the Elang Formation

within the depth 3276m MDDF to 3315 m MDDF (Figure 6.10) and the total gas rangedbetween 5 to 22%.

Based on the petrophysical analysis, the average porosity for the individual sand reservoirhas been calculated to be 8% and the water saturation estimated around 95% (Figure6.9).

MDT measurements in the Elang Formation are inconclusive for fluid analysis since therewere no valid pressure data acquired and thus, no fluid gradient can be established over


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these sand units. Ten (10) MDT points which were acquired from this Formation werefound as lost seal and one (1) supercharged MDT point. The fluid sample was taken fromthe MDT Dual Packer in the depth of 3286.5m MDDF which indicated water with mudfiltrate contamination (Figure 6.11). However, from the onboard analysis on the sample,there is enough contrast between the salinity of the water sample and the salinity of mud

filtrate which was measured prior to MDT to conclude that formation water has beenrecovered. The salinity measured ranged between 41,000 to 44,000 mg/l and 5.2 to 5.7%of NaCl.

Sidewall Core Taker (CST) or conventional core was done in this Formation within thedepth of 3273m MDDF to 3339m MDDF. There were nine (9) recovered core samples andtwo (2) samples were found empty (Appendix 1).

The sample cuttings from Makikit-1 well have been used for petrographic analysis toevaluate the composition and character of Elang reservoir in Makikit-Baleia Structure.From the analysis showing that the Elang formation mostly composed of fragments ofcalcite spar, sandstone rock fragments, pyrite, a mudstone fragment, ferroan dolomite,

and quartz replacement of calcite. The visible porosity observed is within 5-10%. Thedetail of the petrographic analysis of Elang Formation can be seen inFigure 6.12.

7.2 BATHONIAN-BAJOCIAN - PLOVER FORMATION (3339-3417 m MDDF)

The Bathonian-Bajocian Plover Formation sequence is comprised of thick sandstonesinterbedded with thin layer of claystones.

The formation was described, composed of sandstones which overall are occasionallyoff-white in colour, transparent to translucent, fine to very fine grains, occasionally mediumfine grains, sub angular to angular, occasionally sub-rounded, hard to friable, moderatesiliceous cemented, occasionally calcareous cemented, moderate sorted, traces of

glauconites and carbonaceous materials, and poor visual porosity. Claystones in theformation are medium gray to medium dark gray, occasionally hard, sub-platy to platy,occasionally sub-blocky, slightly calcareous, slightly sticky and contained traces of pyrites.Siltstone in the formation are olive black to brownish black in colour, occasionallybrownish gray in parts, firm to hard, occasionally very hard, sub-blocky to blocky,occasionally sub-platy and non calcareous.

The gamma ray response shows a few series of thick blocky low gamma ray pattern whichindicate the fluvial influence sand. The resistivity log does not show any obviousseparation between the shallow resistivity and the deep resistivity log. The density andporosity logs like Elang Formation, also showed the high bulk density (average 2.85 G/C3)and low neutron porosity (average 0.05 V/V) readings. These results had given the early

indication of the tight reservoir for this formation (Figure 6.9).

Only pin-point, pale yellowish direct florescence, without residual ring, no odour oil showswithin the depth 3339-3355 m MDDF was observed. The total gas showed the value of5.43%. Petrophysical analysis indicates a total average porosity of the section at 8%.Water saturation was calculated at 95% (Figure 6.9).

Three (3) valid pressure points were acquired at the depth of 3341m MDDF, 3343.2mMDDF and 3349.4m MDDF and were plotted. This plot showed that the sample point fitted


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well along the water line gradient of 0.43 psi/ft. The other 18 MDT points that beenacquired in this formation found invalid when 1 points was tight, 1 supercharged and 16lost seals. The detail on the MDT results for the Plover Formation is shown in Figure 6.9.

There was no fluid sample acquired from this formation. The side wall cores were taken

from 3341m MDDF until 3411m MDDF within this formation. 11 points successfullyrecovered while 6 were found empty (Appendix 1)..

Based on the petrographic analysis that been done from Makikit-1 ditch cutting samples,showing that the Plover formation is composed of fragments of calcite spar,monocrystalline quartz, sandstone fragments, pyrite, mudstone fragments, dolomitereplacement of calcite, and quartz overgrowths. The visible porosity observed is between1-5%. The detail of the petrographic analysis of Plover Formation can be seen in Figure6.13.

8.0 G&G SPECIALISED STUDY

As per the Baleia-1 program, the specialized studies described below are to beundertaken:

1. Petrography Analysis2. Geochemical Evaluation3. Biostratigraphic Studies

Data and samples which including the well sample cuttings, are to be submitted toselected contractors who will carry out the analysis for PCTSL.

The results of these specialized studies shall be integrated into a final report once they

are all completed.

9.0 HYDROCARBON RESOURCE ASSESSMENT

Pre-Drill resource assessment for the Baleia Structure was computed in 2009, the resultsof which have been presented and endorsed by PCSBs Exploration Review Committee(XRC) in January 2009. Baleia has been categorized as a Structure; with unriskedhydrocarbon initially in place for P50 case of 222 MMSTB of Oil with the Probability ofSuccess (POS) 50%. Baleia-1 was plugged and abandoned with gas show on24 April 2010.

9.1 PETROPHYSICAL ANALYSIS

Based on the petrophysical analysis, found that:

The quality of the open hole wireline logs for Baleia-1 was good. The holecondition also looks good based on the available ultrasonic caliper and input fromdrilling. The 3 valid pressures from the first MDT run plotted out as a watergradient


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However, from water saturation computation using the logs, some hydrocarbonstill exist which most likely is residual oil.

The water sample that was taken at 3286.5m MDDF is contaminated with mudfiltrate. However, from the onboard analysis on the sample, there is enough

contrast between the salinity of the water sample and the salinity of mud filtratewhich was measured prior to MDT to conclude that formation water has beenrecovered

Also, during the MDT Dual Packer operation at that water sample station 21 litersof fluid was pumped through the MDT Dual Packer tool. Taking into account 14liters is the fluid which occupied the 1 meter interval for that station, 7 liters of fluidmust have been pumped from the formation. That amount should give confidencethat formation water have been flowed into the tool.

The sample taken is shown in Figure 6.11 and the post drill Petrophysical parameters areshown onTable 9.2.

Petropyhysical Parameters for gas case at Elang/Plover Formation

RESERVOIR

Depth

Gross SandThickness

N/G

Average,PHIT (from

Netsandration)

AverageSw, Swt

(fromNetpay

ratio)

Top Marker Bottom Marker

m MDDF m TVDSS m MDDF m TVDSS

ELANG/PLOVER 3285.0 3246.6 3325.0 3286.6 30.0 0.41 0.08 0.95

Table 9.2: Petrophysical Parameters for gas case at Elang/Plover Formation

The detail of the Petrophysical parameters of Baleia-1 is shown in Appendix 2.

9.2 RISKING ON PETROLEUM SYSTEM

The Makikit-Baleia structure risking and raking is conducted based on the post-drillevaluation results of Makikit-1and Baleia-1 wells. The assessments of each elements ofthe Petroleum System are based on confident level from G & G interpretation of eachremaining Structure.

9.2.1 SOURCE ROCK

Presence (Certain to Very Likely): Based on the well sample analysis on Makikit-1 well,there were good quality of gas prone and oil prone organic matter. In term of quantity, The

TOC is poor to good (0.1 to 2.19 wt %). The TOC content was increased with depth. Theinterval is thermally immature to mature with respect to hydrocarbon generation.Therefore, the occurrence of hydrocarbon charge was valid. The effective source rock forthis block is the mid-Jurassic Plover intra-formational shale, which based on depositionalenvironment, contains mainly Type III kerogen. These can provide direct hydrocarboncharge into the overlying sandstone reservoirs. Traps can be charged by either in-situsource rock or short-distance lateral migration from source rock in Flamingo Syncline. TheFIS studies on Makikit-1 wells show that the Elang/Plover reservoirs are charged andhydrocarbon prone at a moment of time.


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Effectiveness (Very Likely): The Plover Intra-Formational shale (main source rock)expected to begin generating & expelling hydrocarbon since Early Tertiary and at present-day, are in the Late Generation phase (TR=65%-85%). The in-house basin modelingconcluded that the Makikit-Baleia structure demonstrate significant possibilities forhydrocarbon accumulation.

9.2.2 RESERVOIR

Presence (Very Likely to Probable): Elang/Plover reservoir is a proven sandstonereservoir, prone for hydrocarbon accumulation based on regional wells result. Thereservoir thickness is approximately 500m and wide spread evenly within the BonaparteBasin.

Effectiveness (Probable): Based on Makikit-1 well sample analysis results, the visibleporosity ranges from 1-5% in the sandstone ditch cutting samples. Pore types aregenerally minor secondary dissolution porosity with lesser primary intergranular showingoverall isolated to very poor interconnectivity. Reservoir quality generally ranges from poor

to very poor in these sandstone samples. Therefore, diagenesis had strongly affected thereservoir quality of sandstones in Makikit-1 with the main factor being quartz overgrowthcementation.

9.2.3 TRAP

Presence (Probable): The 3D seismic data with good to average data quality is used tointerpret the Makikit-Baleia structure. The Makikit-Baleia structure is interpreted as a threeway dip closure and the structure map is corrected based on Makikit-1 well results. Thecorrection and remapping gives confident on the structure presence.

Effectiveness (Probable): Many of the drilled structures have relatively high percentageof partially filled or breached Jurassic oil columns. The significantly high gas readingsobserved in Darwin Formation at Makikit-1 and Baleia-1 wells show that the hydrocarbonmay has escape through the fault and accumulates at shallower formation. The FluidInclusion studies conducted at Makikit-1 well shows that the structure was filled withhydrocarbon at a moment of time and the fault reactivation may lead the trap to breachthe hydrocarbon to the shallower Formations.

9.2.4 MIGRATION

Presence (Certain to Very Likely): Based on horizon flattening on seismic based onages, all the identified remaining structures presents since Late Cretaceous age. Thehydrocarbon expulsion is between 65Ma (Paleocene) until present-day.

Effectiveness (Very Likely): The mid-Jurassic Plover intra-formational shale can providedirect hydrocarbon charge into the overlying sandstone reservoirs. The efficiency of themigration routes from source rock to sandstone reservoir studied in-house agrees withMakikit-1 well results that indicate the presence of hydrocarbon based on gaschromatography results and oil shows within the target reservoir.


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10.0 CONCLUSIONS

The Baleia-1 was drilled and reached TD at 3414.6 mTVDDF.

There are two possible reasons for Baleia-1 well failure. Firstly, the main reason is the seal

integrity corresponds to the northwest-southeast fault across the structure which is not sealingand allowing the hydrocarbon escape to the shallower formation. The block evaluation justifythat most of the identified Structures have relatively high percentage of partially filled orbreached Jurassic hydrocarbon columns. The hydrocarbon observed in Darwin Formation atBaleia-1 well shows that the hydrocarbon accumulate at Elang and Plover Formations mayhas escape through the faults and accumulate at shallower formation. The Fluid Inclusionstudies conducted at Makikit-1 well shows that the structure was filled with hydrocarbon at amoment of time and the fault reactivation may lead the trap to breach the hydrocarbon to theshallower Formations.

Secondly is the reservoir depth and cementation, which had reduced the porosity andpermeability. This is clearly demonstrated on Makikit-1 well results which claim that diagenesis

had strongly affected the reservoir quality of sandstones with the main factor being quartzovergrowth cementation. However, the ongoing Baleia-1 well analysis results may furtherdemonstrate the reservoir failure in term of the porosity reduction.

The Petroleum System in term of source rock and hydrocarbon migration is proven to bepresence. The high gas reading concludes that the Baleia Structure is located within thehydrocarbon migration pathway.

Finally, the well was Plugged and Abandoned as a gas show well and all the available data willbe used for further study in the area.


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FIGURES


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Coleraine 1

Minotaur 1

Elang 1

250000 mE 300000 mE

Elang 2

Elang 3

Naga1

Mandar 1

800000mN

Makikit-1

Basilisk 1

Baleia-1

LESTE

Timor SeaJoint

PetroleumDevelopment

Area

(JPDA)Block

JPDA 06-

102

Location of the Baleia-1 Well

10km

JPDA

06-102

Bayu 2

Bayu 4

Trulek 1

Bayu 3

Hingkip 1

Fohn 1

Bayu 5Bayu 1

Mistral 1Undan3

Undan 2

Undan 1

8750000mN

Kurita-1/ST1

Figure 1.1: Location of the Baleia-1 Well


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MSL 34.8 m

Seabed 77.0m

20Casing

722m TVDDF

8-1/2 Pilot Hole / 26 Hole

Baleia-1 Drilling Program Plan versus Actual

PRE-DRILL DRILLING PROGRAM (PLAN)

MSL 34.8 m

Seabed 78.6 m

20Casing

715.6m TVDDF

8-1/2 Pilot Hole / 26 Hole

POST-DRILL DRILLING PROGRAM (ACTUAL)

13-3/8 Casing

2185m TVDDF

9-5/8Casing

3272m TVDDF

7 Liner (Contingency)

3535m TVDDF Baleia-1

17-1/2 Hole

12-1/4 Hole

8-1/2 Hole

13-3/8Casing

2182.7 m TVDDF

9-5/8Casing

3266.8 m TVDDF

Open Hole

3414.6m TVDDF

Baleia-1

17-1/2 Hole

12-1/4 Hole

8-1/2 Hole

Figure 1.2: Baleia-1 Drilling Program Plan versus Actual


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Logging Program for Baleia-1

Hole Size Mud Planned Depth: 3272m TVDDF 3535m TVDDF Actual Depth: 3266.8m TVDDF 3414.6m TVDDF

8.5 WBM Run 1:FMI-DSI

Run 2:MDT

Run 3:

Run 1:FMI-DSI

Run 2:MDT

Run 3:VSP

Run4:CST

MDT Dual Packer

Run 3:VSP

Run 4:

CST

Figure 1.3 : Baleia-1 Logging Program


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FORMATIONPrognosis Depth Actual Depth

Diff

(m-TVD)

m MDDF m TVDDF m TVDSS m MDDF m TVDDF m TVDSS -Hi / +Lo

SEABED 115.4 115.4 77.0 117.0 78.6 40.2 -36.8Oliver Formation 691.4 691.4 653.0 691.0 690.6 652.2 -0.8

Hibernia Formation 737.4 737.4 699.0 738.0 737.6 699.2 0.2

Johnson Formation 1545.4 1545.4 1507.0 1548.0 1546.9 1508.5 1.5

Vee Formation 2023.4 2023.4 1985.0 2044.0 2042.8 2004.4 19.4

Top Formation Depth Prognosis versus Actual Depth

Wangaralu Formation 2449.4 2449.4 2411.0 2470.0 2468.6 2430.2 19.2

Darwin Formation 2948.4 2948.4 2910.0 2987.0 2985.2 2946.8 36.8

Echuca Shoals

Formation 3019.4 3019.4 2981.0 3030.0 3028.1 2989.7 8.7

Elang Formation 3270.4 3270.4 3232.0 3273.0 3270.8 3232.7 0.7

TD 3538.4 3538.4 3500.0 3417.0 3414.6 3376.2 -123.8

Figure 1.4: Baleia-1 Top Formation Depth - Prognosis versus Actual Depth


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N

JPDA 6 1 2

JPDA

Index Map

JPDA

Index MapMinotaur-1

Naga-1

Coleraine-1

Block JPDA 06-102 Seismic Database Map

10 km

Fohn-1

2D 6000 line-km

.Full Fold

Figure 4.1 : Block JPDA 06-102 , 2D and 3D Seismic Database Map.


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Baleia-1 Well Synthetic Seismogram

Figure 4.2 : Synthetic Seismogram of Baleia-1 well.


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Makikit-1 Well Synthetic Seismogram

Figure 4.3 : Synthetic Seismogram of Makikit-1 well. Increasing impedance were seen as trough.


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Makikit-1 AVO Synthetic Seismogram

Figure 4.4 : Synthetic is in Reverse Polarity. Type 3 AVO sands, becomes dimmer with offset.


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Makikit-1 VSP Geogram

ACOUSTICIMPEDANCE

SONICINT.VELOCITY

DENSITY

NEUTRONPOROSITY

GAMMARAY

RESISTIVITY

CALIPER

VSP Upgoing (Normal Polarity)

Top Elang

BaseAptian

Figure 4.5 : Makikit-1 VSP Geogram in Normal Polarity.


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-3300

-330

0

-3300

-3300-3300

-3300

-3400

-3400-3400-3400

-34

00

400

-3400

-3500

-3500

-3500

-3600-35

00

-3200

-3200-3200

-3300

-3300

-3300 -3300 -3300

-3300

-3300

-3300

-3300

-3300

-3300

-3200

-3200

-3200

-3200

-3200

-3

50

0

-3500

-3500

-3500

-3400

-3400 -3400

-3400

-340

0

-3400

-340

0

-3400

-3400

-3400

-3500

Baleia-1Makikit-1

240000 244000 248000 252000 256000 260000 264000 268000

8792000

8796000

8800000

8792000

87960

00

8800000

Y,

[m]

240000 242000 244000 246000 248000 250000 252000 254000 256000 258000 260000 262000 264000 266000 268000

8792000

8796000

8800000

8792000

8796000

8800000

Top of Elang Depth Structure Map

Top of Elang Post-Drill Depth Structure Map

-32

00

-320

0

-3200

-32

00

-3300

-3300

-3400

-3400

-3400

-3500

-3400

-3400

-3400

-3400

-3400

-3400

-3400

-

240000 244000 248000 252000 256000 260000 264000 268000

X, [m]

8788000

8788000

240000 242000 244000 246000 248000 250000 252000 254000 256000 258000 260000 262000 264000 266000 268000

8788000

8788000

0 1000 2000 3000 4000 5000m

1:125000

-3640

-3600-3560-3520

-3480-3440-3400

-3360-3320

-3280-3240

-3200-3160

-3120

Depth

Timor Leste

Block JPDA 06-102

Post Well Baleia-1

Depth Structure Map

Top of Elang

Contour inc

Date

Signature

20

04/29/2010

Map

Figure 4.6 : Top of Elang Post-Drill Depth Structure Map


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Inline 2301 Through Baleia-1 Well

NW SE

Turonian MFS

Base Eocene

Base Aptian

Base Flamingo

Figure 4.7 : Interpreted 3D Seismic In-Line 2301 through Baleia-1 well.


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Inline 2301 Through Baleia-1 WellNW SE

GR

Base Ap

BaFla

Figure 4.8 : Interpreted 3D Seismic In-Line 2301 through Baleia-1 well zoom-in at the reservoir level.


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Crossline 3784 Through Baleia-1 WellSW NE

Turonian MFS

Base Eocene

Base Aptian

Base Flamingo

Figure 4.9 : Interpreted 3D Seismic Cross-Line 3784 through Baleia-1 well.


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Crossline 3784 Through Baleia-1 Well

GR

SW NE

Base Aptian

BaseFlamingo

Figure 4.10 : Interpreted 3D Seismic Cross-Line 3784 through Baleia-1 well zoom-in at the reservoir level.


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GR GR

W E

Turonian MFS

Random Line Through Makikit-1 and Baleia-1 Well

Base Aptian

Base

Flamingo

Figure 4.11 : Interpreted 3D Random Seismic Line through Makikit-1 and Baleia-1 well.


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Makikit-1 vs. Baleia-1 Time/ Depth Curve

Top Hibernia

Top Johnson

Y= 0.00002X + 1.5766X 139.19

Top Wangarlu

Top Echuca Shoals

Top Elang

Figure 4.12 : Makikit-1 and Baleia-1 Time Depth Curves.


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Tectonic Elements of Bonaparte Basin Litho-Chronostratigraphy of Bonaparte Basin

Cretaceous

Tertiary

Oblique left lateral collision of Australian andEurasian plates. 5Ma deformation. Development of

proto- foreland basin (Timor Trough). Strong

subsidence in Malita & Cartier Troughs &re-activation as pull apart depocentres

Late Miocene

(8-5Ma)

Subduction of northern part of Australian plate

with Philippines plate

Late Eocene -

Oligocene

Thrusting on Timor and Timor / Australian

convergence ceased. Throws on flexural faultingdecreased. Closure formed at Greater Sunrise

Pliocene

(3Ma)

Rapid uplift of Timor Island and collapse of Timor

Trough

Pliocene

(~2Ma)

Continued northern movement of Australian plate atrate of 5- 8 cm / year

Presentday

-Eurasian plates. 5Ma deformation. Development of

proto -

Late Miocene

(8-5Ma)

Oligocene

Thrusting on Timor and Timor / Australian

convergence ceased. Throws on flexural faultingdecreased. Closure formed at Greater Sunrise

Pliocene

(3Ma)

Rapid uplift of Timor Island and collapse of Timor

Trough

Pliocene

(~2Ma)

Presentday

Further thermal decay & passive continentalAptian

Northward movement of Australian plateCenomanian Northward movement of Australian plateCenomanian Northward movement of Australian plateCenomanian

flexural TOP SEAL:- Flamingo Fm

(Berrisian)

SOURCE ROC

-Echuca Shoal F

(Barremian)

PetroleumSystem

of BonapaBasin

Paleozoic

Triassic

Jurassic

Modified from RPS/ECModified from RPS/EC

Block

JPDA 06-102

Thermal decay in crust & passive continental

margin sagging towards widening ocean

ValanginianValanginianValanginian

Creation of Petrel Sub- b as in . ?P rotoformation

Late Dev EarlyCarboniferous

Initiation of Westralian Superbasin. Creation ofMalita & Swan Graben. Overprinting of earlierstructures

End Carboniferous Early Permian

Early Fitzroy movement. Extensive coarse fluvio-deltaics in response to uplift

Norian Carnian

Rifting of micro- continents to NW of Bonaparte,Block faulting, thermal doming & local red beds.Formation of Flamingo High. Growth of SahulPlatform and possibly Ashmore Platform

Late TriassicEarly Jurassic

Rifting of micro-continents along Gondwana edge &first deep marine conditions introduced to super

basinRifting in Malita, Sahul, Nancar& Vulcan Graben

Callovian-Oxfordian

Fault- controlled basin development

Kimmeridgian extension & block faulting in theNancar Trough

KimmeridgianBerriasian

- -Carboniferous

Initiation ofMalita & Swan Graben. Overprinting of earlierstructures

deltaics-

Rifting of micro-Block faulting, thermal doming & local red beds.Formation of Flamingo High. Growth of SahulPlatform and possibly Ashmore Platform

Late TriassicEarly Jurassic

-Callovian-Oxfordian

Kimmeridgian extension & block faulting in theNancar

KimmeridgianBerriasian

Sahul Syncline

RESERVOIR

-Elang/Plover Fm

(Callovian)

-Flamingo Shale

(Berrisian)

-Plover intra-

formational sha

(Callovian)

Figure 5.1: Stratigraphic Summary of the Bonaparte Basin


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JPDA 106-102

100 km

Figure 5.2: Tectonic Elements of the Bonaparte Basin


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Baleia-1 Post-Drill Correlation

A A

Figure 6.1: Baleia-1 Post-drill well correlation


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Horizon Flattening at Makikit-Baleia Prospect

Hydrocarbon

Generation at Early

Paleocene (65 ma)

and Expulsion at 55ma.

Flatten @ Base Eocene

@ 45ma

Flatten @ Turonian

@ 90ma

Flatten @ Base Aptian

@ 120ma

NW SE

Structures formation Flatten at Base Aptian

(120ma), Turonian

(90ma), Base Eocene

(45 ma)

Makikit-Baleia

Structure form -pre-date the HCgeneration and

expulsion

In Line 2200

Figure 6.2: Baleia-1 Horizon Flattening at Makikit-Baleia Prospect


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High gas reading observed @ Darwin Fm.

The hydrocarbon possibly leak along the

fault and accumulate in higher Formations.

The fault displacement at crestal is

approximately 350m which able all theaccumulation leak to shallower Fm. along

the fault.

Sourc

Elang /Plover shale

NW SE

Top Echuca Shoals

Top Elang/Plover

N W S E N W S E N W S E

Possible Hydrocarbon Migration Path

G R

B a s e A p t i a n

B a s eF l a m i n g o

G R

B a s e A p t i a n


G R

B a s e A p t i a n


Figure 6.3: Baleia-1 Possible Hydrocarbon Migration Path


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Fluid Inclusion Stratigraphy (FIS) Results (Makikit-1)

Figure 6.4: Fluid Inclusion Stratigraphy (FIS) Results (Makikit-1)


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Kerogen Type and Maturity Profile for Makikit-1

Kerogen Type for Makikit-1 Maturity Profile for Makikit-1

Kerogen Type III Terrestrial

Depositional Environment

Figure 6.5: Kerogen Type and Maturity Profile for Makikit-1


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TOC: n/aHI: n/aVRo: 0.75%

TOC: 0.88wt%HI: 283VRo: n/a

TOC: 0.97wt%HI: 281VRo: 0.86


FlamingoForm

ation

(3071-3262mM

DDF)

- Flamingo and Echuca Shoals Formations are predominantlyshale/claystone.

- The source rock shales at Makikit-1 contained slightly higher TOC

value compare to Mistral-1 and but have similar trend of high HIvalue, indicating presence of good quality organic matters.

- TOC value at Makikit-1 ranging between 0.45 and 1.10 wt% .

Source Rock in Flamingo and Elang/Plover Formations (Makikit-1)

MAKIKIT-1


TOC: 1.62wt%HI: 146VRo: 0.92%



TOC: 1.50wt%HI: 154VRo: 0.90


Elang/PloverFormation

(32623460m

MDDF)

-The high TOC shales are thin (2-3m) interbeded between thicksand.

- TOC value at Makikit-1 quite similar with the nearby Mistral-1 well,ranging between 1.50 and 2.50 wt%.

- Makikit-1 shales are at slightly higher maturity level, at present-

day.

Figure 6.6: Source Rock in Flamingo and Elang/Plover Formations (Makikit-1)


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Post-drill Present-Day Maturity Map at Top of Plover FM (sr)

Post-drill Present-Day Hydrocarbon Generation

Phase Map at Top of Plover FM (sr)

68mW/m2

63 mW/m2

56 mW/m2

65 mW/m2

Proposed Basal (Base of Plover Shale) Heat Flow Model

Figure 6.7: Post-drill Present-day Maturity Map and Hydrocarbon Generation Phase Map at Top Plover Formation (s


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JPDA 06-102 Post-drill Timing of Oil and Gas Expulsion Charts

Timing of Oil Expulsion (at PS-01 well)

PS-01

Timing of Gas Expulsion (at PS-01 well)

Figure 6.8: JPDA 06-102 Post-drill Timing of Oil and Gas Expulsion Charts


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Baleia-1 - Petrophysical Logs Analysis Results

Figure 6.9: Baleia-1 - Petrophysical Logs Analysis Results


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Baleia-1 Elang Formation - Sample Cuttings Description

Figure 6.10: Baleia-1 Elang Formation - Sample Cuttings Description


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Baleia-1 Elang Formation water sample

Recovered water samples from 3,286.6mMD

Figure 6.11: Baleia-1 Elang Formation water sample


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Makikit-1 Elang Formation Petrographic Analysis

Figure 6.12: Makikit-1 Elang Formation Petrographic Analysis


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Makikit-1 Plover Formation Petrographic Analysis

Figure 6.13: Makikit-1 Plover Formation Petrographic Analysis


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APPENDIX 1

BALEIA-1 SIDE WALL COREDESCRIPTION


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APPENDIX 2

BALEIA-1 PETROPHYSICALEVALUATION REPORT


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PETRONAS CARIGALI (TIMOR SEA) LTDSidewall Core Description

Well Name: Baleia-1 Wireline Contractor: Schlumberger Wireline

Block: JPDA 06-102 Wireline Engineer(s): Reuben & Callum

Date 13/04/2010 For Rotary SWC For Percussion SWC

SWC Type Percussion Number of Run N/A Bullet type Hard rock & Combo

Hole Size 8.5 Number of Cut N/A Shot 30

Log suiteSuite 1 Number of Recovery N/A Misfired -

Run 5 % Recovery N/A Lost -

Geologist Farahida & Rajeevan Recovery (%) 73

NoDepth

(mMDDF)

RecoveryLithology

Oil show

(Tr,P,F,G)

Vis Por

(P,F,G)

Detail Description

(Lithology, visible porosity and hydrocarbon shows) and remarkscm Cond.

1. 3411 - Broken SST - P

Translucent to transparent, occasionally off white, moderate hard to hard,

occasionally very hard, fine to very fine grain, moderately cemented, poor

visible porosity, No Show

2. 3408 1.5 Good SST - PTranslucent to transparent, occasionally off white, moderate hard to hard,occ very hard, fine to very fine grain, moderately cemented, poor visible

porosity, No Show

3. 3405 2.0 Good CLYST - -Medium gray to medium dark gray, occasionally dark gray, soft to firm,

slightly calcareous, traces of glauconite

4. 3399 - - - - - Empty

5. 3396 1.0 Broken SST - N


occasionally very hard, fine to very fine grain, moderate to highly cemented,

no visible porosity, No Show

6. 3393 2.0 Good SST - PTranslucent to transparent, occasionally off white, moderate hard to hard,

occasionally very hard, fine to very fine grain, moderately cemented, poor


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7. 3386 2.0 Good CLYST - - Medium gray to medium dark gray, occasionally dark gray, soft to firm,slightly calcareous

8. 3382 2.0 Good SST - N


occasionally very hard, fine to very fine grain, moderately cemented, no


9. 3377 1.3 Partial SST - N


occasionally very hard, fine to very fine grain, moderate to highly cemented,

no visible porosity, No Show

10. 3373 - - - - - Empty

11. 3369 - - - - - Empty

12. 3366 - - - - - Empty

13. 3363 - Broken CLYST - -Medium gray to medium dark gray, occasionally dark gray, soft to firm,

slightly calcareous

14 3358 1.5 Partial SST - PTranslucent to transparent, occasionally off white, moderate hard to hard,fine to very fine grain, trace of glauconite, moderately cemented, highly

calcareous, poor visible porosity, No Show

15 3352 2.2 Good SST - P


fine to very fine grain, trace of glauconite, moderately cemented, highly

calcareous, poor visible porosity, No Show

16 3347 - - - - - Empty

17. 3341 - - - - - Empty

18. 3337 1.5 Partial SST - PTranslucent to transparent, moderate hard to hard, fine to very fine grain,

highly siliceous cemented, very poor visible porosity, No Show


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slightly calcareous


occasionaly hard, slightly calcareous

21. 3323 1.4 Partial CLYST - -Medium gray to medium dark gray, occasionally dark gray, soft to firm,

slightly calcareous

22. 3315 - Broken SST - P

Translucent to transparent, moderate hard to hard, fine to very fine grain,

moderate siliceous cemented, occasionally calcareous cemented, poor visible

porosity, No Show

23. 3308 2.5 Good SST - PTranslucent to transparent, moderate hard to hard, fine to very fine grain,

highly siliceous cemented, traces of pyrite, poor visible porosity, No Show

24. 3302 2.0 Good SST - PTranslucent to transparent, moderate hard to hard, fine to very fine grain,

slightly siliceous cemented, poor visible porosity, No Show


slightly calcareous

26 3290 - - - - - Empty

27 3286 2.1 Good SST - PTranslucent to transparent, moderate hard to hard, fine to very fine grain,

slightly siliceous cemented, highly calcareous, poor visible porosity, No Show

28 3283 0.8 Partial SST - P

Translucent to transparent, moderate hard to hard, fine to very fine grain,

slightly siliceous cemented, traces of carbonaceous material, traces of

glauconite, poor visible porosity, No Show

29 3278 1.9 Good CLYST - -Medium gray to medium dark gray, occ dark gray, soft to firm, slightly

calcareous

30 3273 - - - - - Empty

*Notes: 1. 22 Recovered, 8 Empty


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ENCLOSURESTOP ELANG RESERVOIR

DEPTH STRUCTURE MAP

BALEIA-1 Well Evaluation Report

Documents

makikitbaleia structurefigure

synthetic seismogram

reservoir evaluation

geological evaluation

timor sea block jpda

drill summary

hydrocarbon source

petroleum system summary