Post on 22-Jan-2023
Field Evaluation Report
First compiled: February 2002Last modified: December 2009
– Far East –
Sirikit FieldPhitsanulok Basin, Thailand
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© C & C Reservoirs. All Rights Reserved.
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Executive Summary
The Sirikit Field is located in the Phitsanulok Basin,~400 km north of Bangkok (Fig. 1). It wasdiscovered in 1981 and brought onstream in 1982.The field has a STOIIP of 800 MMB (this mayinclude satellites) and ultimate recoverable reservesfor the Greater Sirikit Area are 148 MMBO and 250BCFG (2001). It is the largest oilfield onshoreThailand, holding close to one third of oil reserves inthe country. The field produces sweet light waxy oil(39-40 oAPI, 15-20% wax), termed the ‘Phet crude’.The oil and gas are trapped in a heavily faulted,north-trending anticline by a combination of faultand dip closure and there are numerous, separatefault compartments. The reservoirs in the main fieldare predominantly lacustrine-delta sandstones ofthe Miocene Lan Krabu Formation. Lacustrineclaystones form the source and seal in the basinand are arranged in cyclical sequences with thereservoir sandstones. Small accumulations to thewest and north of the main field are hosted byyounger fluvial sandstones. Development of Sirikitcommenced in 1982 and has continued to thepresent (2008). Water injection supplements weaksolution-gas and gas-cap expansion natural drives.The water injection programme was implemented in1995 to provide pressure support and improveoverall recovery rates. The application of the latestexploration and production technology has resultedin an increase in recoverable reserves from 30MMBO to 148 MMBO in less than twenty years. By2000, 128 MMBO and 276 BCFG had beenproduced. It was hoped to maintain a productionrate of ~24,000 BOPD from the Greater Sirikit Areauntil 2010 but in 2004 and 2005 average dailyproduction had declined to ~17,000 BOPD.
Exploration History
The Phitsanulok Basin contains the Sirikit Field andseveral smaller fields, including West Sirikit, PruKrathiarn and Thap Raet (Figs. 1 and 2), instructural traps within fluvial and lacustrine deltareservoirs (Polahan, 1986). The basin, whichcovers over 6000 km2, was defined in the late1970s through fieldwork and aeromagnetic surveys.Shell was granted the S1 concession in the centreof the basin in 1979. Shell acquired and interpreted>2000 km of 2-D seismic data over the block in1980 and 1981 and 4000 km in 1982 (Fletcher,1982, 1983; Fletcher and Soeparjadi, 1984). Twowell locations were selected, based on the results ofthe seismic surveys, and the second well, LKU AO1,discovered the field at the end of 1981. Thediscovery well was very encouraging; it tested atrates up to 4400-4600 BOPD, RFT tests suggesteda long oil column and the STOIIP was initiallyestimated to be ~1 BBO (Brooks, 1987). A decisionwas made to develop the field and an earlyproduction scheme was implemented. The timefrom discovery to initial production was just twelvemonths. Development drilling commenced in 1982,five producers were completed and the field wasbrought onstream by the end of the year. The field,initially known as Lan Krabu, was officiallyinaugurated in 1983 and renamed the Sirikit Field(Shell, 2001).
Five wells were drilled as part of the initial appraisalprogramme. Four of the wells in the north of thefield indicated: (1) a deeper GOC (1555 m TVDSS)than that found in the discovery well (1435 mTVDSS); (2) hydrocarbons were in separatereservoir sands; and (3) flow rates that were lowerthan in the discovery well. Consequently, furtherappraisal wells were drilled and a 3-D seismic
SIRIKIT FIELDMiocene Lan Krabu Formation:Lacustrine-Delta Sandstones
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survey was acquired over the field in 1983-84. Thenortheast of the field is structurally simple and sowas developed first. After the 3-D seismicinterpretation was completed, appraisal anddevelopment were focused on the eastern andcentral parts of the field. In 1985 an appraisal wellon the western flank and a well at the southern endof the field both found GWCs at the same level, thusdowngrading expectations of oil in those areas(Brooks, 1987). The western portion of the field,which is structurally complex, was appraised anddeveloped last.
Once Sirikit production was established, explorationfocused on satellite accumulations and on deeperobjectives in the main field. Sirikit West wasdiscovered in 1983, has a STOIIP of 34 MMB, partlyin younger fluvial reservoirs, and came onstream in1985. Over 50 exploration wells have been drilledon the block (OGJ, 1999a). Additional STOIIP hasbeen found in deeper reservoirs (Brooks, 1987), inthe Pru Krathiam and the West and East Sirikitsatellites and gas reserves have been added on thewest flank of the field. An active explorationprogramme continues on the block.
Basin Evolution and Petroleum Systems
The Sirikit Field lies on a basement-cored high inthe southwest of the Phitsanulok Basin in north-central Thailand (Fig. 1). It is one of a series ofelongate north trending extensional basins foundonshore and offshore Thailand (Fig. 3). The basinwas initiated in the Late Oligocene in response toregional strike-slip movement in the Thai-MalayMobile Belt which represents a Permo-Triassiccollision zone between the Shan-Thai andIndochina continental blocks (Fig. 4) (Polachan etal., 1991). The tectonic activity and basindevelopment during the Tertiary in SE Asia arerelated to the collision of the Indian and South AsianPlates however the details of this process arecomplex and controversial, for example with regardto the amount and sense of displacement on themain strike-slip faults (Polachan et al., 1991).
Seven major Cenozoic basins are found in centralThailand, within the mobile belt: the Phitsanulok,Phetchabun, Nang Bua, Suphan Buri, Mae Sod,Kamphaeng Saen and Ayutthaya basins. They arehalf grabens, bounded by north trending, low-angle(30-45o) extensional faults that formed in responseto movement on the regional NE-trending strike-slipfaults. The most significant strike-slip faults are theNW trending Mae Ping and Three Pagoda Faultsand the conjugate, NE trending Uttaradit andRanong Faults (Fig. 4). The NE-tending faults areterminated by the principal NW-trending strike-slipfaults (Fig. 4). Phitsanulok, formed at theintersection of the Uttaradit and Mae Ping Faults, isthe largest and deepest of the Cenozoic basins(Fig. 5). It is 100 km long and 40 km wide and isdeepest adjacent to the western boundary faultwhere up to 8 km of sediments have accumulated(Flint et al., 1989). The north trending westernboundary fault dips at an unusually shallow angle of35-45° (Flint et al., 1988). The basin is floored byMesozoic to Paleozoic sedimentary, igneous andmetamorphic rocks and is surrounded by highlydeformed Mesozoic and Paleozoic sedimentaryrocks.
Major tectonic activity commenced in the LateOligocene and the main phase of strike-sliptectonics occurred at this time (Polachan et al.,1991). The intracratonic basins formed byextension or pull-apart, followed by rim uplift, rapidasymmetric basin subsidence and sedimentation.By Early Miocene time, lacustrine conditions wereestablished in the onshore basins. Local inversionand uplift occurred in the Late Miocene. The LateMiocene unconformity is capped by basaltic lavasdated at 10.3 Ma (Polachan et al., 1991) in thePhitsanulok Basin. Subsidence recommenced inthe Late Miocene and continued to Recent time.
The Phitsanulok Basin contains the Cham Saengpetroleum system. There is a cyclic repetition oforganic-rich claystones that formed during phasesof lake expansion with progradational fluvio-deltaicsandstones. The former provide the source rocks
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and the seals whereas the latter are the reservoirs.The source rocks are up to 400 m thick (Sladen,1997) and belong to the Lower-Middle MioceneChum Saeng Formation. Coals are also presentlocally. Freshwater and terrestrial palynofacies andfreshwater gastropod fossils confirm the lacustrineorigin of the source rock. The source rocks have ahigh content of Type I kerogen derived fromfreshwater algae and Type III kerogen from higherplants. Source kitchens occur in the deepest part ofthe basin, north of the field. The oils are relativelyimmature, have not been biodegraded and are lowin aromatics. Variations in isotopic ratios betweendifferent oil pools may reflect sourcing at differentstages of source rock maturation, while similaritiesin chromatograms indicate common source andmigration histories (Lawwongngam and Philp,1991). Oil generation may have commenced in thePliocene in the west of the basin, where heat flow ishigh. Generation and expulsion may have takenplace at a depth >4 km (Knox and Wakefield, 1983).
Structure and Trap Definition
The main Sirikit Field is a north-trending faultedanticline, developed over a basement high with thesame trend in the southern part of the PhitsanulokBasin. The anticline developed as part of anextensional or pull-apart fault complex in theOligocene in response to transtensional sinistralshear on the Mae Ping and Uttaradit fault systems(Fig. 6). Basement faulting continued during thedeposition of the main reservoir (Lan Krabu) andceased in late Middle Miocene times (Brooks,1987). The main faults have listric geometries,trend roughly north and have been reactivated andmodified by sinistral strike-slip (Flint et al., 1988,1989). The strike-slip has produced synthetic andantithetic faults and Reidel shears which have acharacteristic sigmoidal shape and a ~NWorientation (Flint et al., 1988). Oil and gas arestructurally trapped in multiple pools on the faultedanticline.
The main Sirikit Field is ~8 km long by ~6 km wideand covers an area of ~12,000 ac. The main
structure plunges to the NNW and is dip and faultclosed to the west by a complex extensional faultsystem. It is fault and dip closed to the north andeast (Figs. 7, 8 and 9). The reservoirs typically dipat 10o to the ENE.
The main reservoir in the main Sirikit Field is the KMember of the Lan Krabu Formation, whichcontains both oil and free gas, but there are severaldeeper oil reservoirs, including the L and MMembers of the same formation (Fig. 10). The crestof the main Sirikit Field is at 1350 m TVDSS (top KMember) and the crest of the L Member is at 1550m TVDSS. The main field has a widespread GOCat 1555 m TVDSS in the K Member and OWCs at1641 m and 1930 m TVDSS in the K and LMembers, respectively (Brooks, 1987). The bulk ofthe recoverable oil lies within the K Member wherethe oil rim is 86 m thick (Brooks, 1987). There is nogas cap in the L Member. Deeper ODTs and OWCsare recorded at 2005, 2050, 2250 and 2400 mTVDSS, in the M and P Members. Fluid contactsare variable on the highly faulted western margin ofthe field. Extensive normal and strike-slip faultsystems compartmentalize the reservoir and somefault blocks have never been charged withhydrocarbons.
Open lacustrine claystones of the Cham SaengFormation that interleave with the Lan Krabusandstones form the seals to the main reservoirs(Figs. 11-13). The ‘Main Clay’ overlies the KMember. It is ~200 m thick on the crest and easternside of the field. An intermediate seal, termed the‘Upper Intermediate Seal’ or UIS, is 20-50 m thick,separates the K and L reservoirs. The top seal tothe M Member is the ‘Lower Clay’ or LIS which is80-300 m thick. The bottom seal to the M Memberand Lan Krabu Formation and top seal to deeperSarabop Formation reservoirs is the ‘BS’ or bottomseal member.
The main Sirikit Field is fault- and dip-separatedfrom the West and East Sirikit and Thap Raet Fieldsby NW and NE trending faults (Figs. 1 and 2).Sirikit-D block is a north trending fault block, with
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fault closure to the W and dip closure to the N, Sand E. It is 3500 m long and 250 m wide. ThapRaet Field consists of four fault blocks, with most ofthe production coming from two in the SW, whichtogether extend for ~2 x 2 km. Sirikit West Fieldoccurs at the triangular intersection of two majorstrike-slip faults (Fig. 14) and consists of severaltilted, down-faulted blocks associated withwestward dipping faults (Chuenbunchom et al.,2003).
Amplitude maps have been used to identify andrapidly map small structural disturbances andsigmoidal anomalies that resemble Riedel shears.The mapping of these small faults is importantbecause of the thinly interbedded nature of thereservoirs (Flint et al., 1988). A ~16 m-thick deltaicwedge within the Upper Intermediate Seal (UIS) hasbeen mapped in the NW of the field (E block) basedon its high amplitude response (Fig. 15) but theapplication of this method for facies mapping isrestricted because of the thinness of the reservoirsrelative to the resolution of the 3-D seismic.
Stratigraphy and Depositional Facies
In the main Sirikit Field hydrocarbons occur inmembers K, L and M of the Early-Middle MioceneLan Krabu Formation which is ~540 m thick (Figs. 8and 12) and in deeper reservoirs beneath the MMember. The Lan Krabu Formation represents thebasal part of the postrift sag sequence. Itunconformably overlies the Kom, Sarabop andNong Bua Formations, which are Oligocene synrift,coarse-grained siliciclastic sediments. Minoramounts of oil also occur in the P Member of thediachronous Sarabop Formation and in so-called‘basement’ which consists of fractured, meta-morphosed, clastic red beds (Smit, 1999). The LanKrabu Formation is overlain by Middle-UpperMiocene Pradu (or Pratu) Tao and Yom Formations(Fig. 16) and these are oil bearing in satellite fields(see below for more details).
The Lan Krabu Formation is 500-2200 m thick andconsists mainly of lacustrine-delta sediments. It
grades into lacustrine mudstones of the ChumSaeng Formation to the south and into alluvial anddelta plain sediments to the north (Fig. 13). Fluvialand alluvial fan deposits of the Prato Tao Formationconformably overlie the Lan Krabu Formation. TheLan Krabu Formation has been divided intoreservoir members or sequences, named from topto base: K, L and M (Fig. 11). These sandymembers are separated by lacustrine shales. Thesequences have been subdivided into submembersand parasequences (Ainsworth et al., 1999). TheLan Krabu Formation thickens off-structure and inSirikit West an additional sequence, the D Member,occurs above K (Fig. 11) (Ainsworth and Sankosik,1998).
Sands of the Lan Krabu Formation were depositedon lobate, river-dominated deltas that advancedrepeatedly into a shallow, extensive, perennial lakein a humid, subtropical climate. The thickersandstones accumulated on prograding mouthbarsand to a lesser extent in fluvial distributary channels(Fig. 17). The progradational sequences are up to~15 m thick and are capped by floodplain and/orlacustrine mudstones and claystones (Flint et al.,1989). Individual distributary channels and mouth-bars are identifiable on wireline logs (Fig. 18).
A detailed core based sedimentological study (Flintet al., 1989) of the Lan Krabu Formation found thatthe commonest sedimentary sequence starts with(1) open lacustrine claystones, passing up into (2)thinly interbedded fine sandstones, mudstones andsiltstones (termed heterolithics) deposited on thedelta front, then (3) cross-bedded fine- to coarse-grained sandstones deposited both on mouthbarsand in channels, and finally (4) either argillaceous,aggradational floodplain deposits or abandonedchannel-fill sediments. The main reservoirs occur inregressive cycles typically 4-8 m thick, representingprogradation of deltas into the main body of thelake. Smaller, 1-3 m thick regressive sequences,commonly containing little or no sandstone, areinterpreted as either distal equivalents of the thick,sandy sequences or the deposits of crevasse deltasformed in interdistributary bays. Regressive, sandy
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sequences are thickest and are best developed inthe middle L and lower K Members. In the model ofFlint et al. (1989), progradation was predominantlyfrom the ENE (Fig. 19) and in a previous paper(Flint et al., 1988) progradation from the NW (intra-UIS delta), from the E (K30/K20) and from the SE(K20) were proposed, whereas more recent papers(e.g., Ainsworth et al., 1999) have favoredprogradation from the N.
Unusually thick (up to 30 m) intervals dominated byargillaceous floodplain deposits occur in the middleof the K Member and in the lower part of the LMember. These may have been related to localizedareas of differential subsidence that allowed thickdelta-top sediments to accumulate or to rapid risesin lake level that led to sediments being trapped onthe flood plain (Flint et al., 1988).
Sirikit-D block, Sirikit West and Thap Raet Fieldscontain oil and minor gas in fluvial sandstones of theMiddle-Upper Miocene Pradu Tao and YomFormations (Fig. 15) (Chuenbunchom et al., 2003)that overlie lacustrine shales of the Chum SaengFormation. The Pradu Tao Formation is ~300 mthick and a shale divides it into two units termedUPTO and LPTO. Similarly, the Yom Formation is~250 m thick and a 5-30 m-thick shale divides it intotwo units named UYOM and LYOM.
Sirikit West also has oil in the D and K Members ofthe Lan Krabu Formation. Stratigraphic units are upto three times thicker in Sirikit West than in the mainfield, indicating synsedimentary movement on themajor fault that separates them (Fig. 14). Theadditional thickness in Sirikit West is mainlyrepresented by shale (Ainsworth and Sankosik,1998; Ainsworth et al., 1999).
Reservoir Architecture
The Lan Krabu Formation in the main Sirikit Fieldis divided into the K, L and M Members orsequences, which have been further divided intoparasequences (Table 1), each 10-20 m thick. The
K Member, the uppermost and main reservoir unit,is up to 320 m thick and has been divided intosubmembers, K1-K4, and seismically definedsequences, K10, K20, K30 and K40 that occurabove reflectors E10, E20 etc. (Figs. 19 and 20A).The main reservoirs are mouthbar and fluvial-channel sandstones with variable reservoir quality.The K20 interval contains a reasonably continuousseismic facies corresponding to progradationaldeltaic cycles. K20 sandstones become thinner andless numerous towards the S of the field (Flint et al.,1988). Sandstones in K30 are more numerous inthe S of the field and mark the maximumprogradation of the delta systems. The UpperIntermediate Seal which occurs above the LMember (Fig. 20A) is characterized by continuoushigh amplitude reflections, however, towards thenorth reflections disappear and amplitudes changeas a result of the appearance of sandy deltaicwedges within the shales. The L Member is 190 mthick and reservoirs are predominantly channelsandstones. On seismic it produces continuous,high amplitude reflections though these convergeand disappear towards the N, W and E of thedataset (Flint et al., 1988). It is subdivided intoparasequences L1-L6, with moderate reservoirquality. The M Member is 70 m thick and compriseseight submembers M1-M8, with poor to moderatereservoir quality.
Sands were sourced from the north of the basin andthe N:G ratio and net thickness decreases towardsthe south of the field (Flint et al., 1988; Finley et al.,1996).
Fieldwide claystones seal the reservoirs and can beeasily recognised on downhole logs because theyhave low sonic velocities and high GR responses(Figs. 12, 18 and 20A). Flooding surfaces at thebases of the transgressive claystones are used forcorrelating the reservoirs and seals between thewells (Figs. 19 and 21). The correlations developedin the 1980s emphasized the lateral continuity ofreservoir sandstones and Flint et al. (1989) reportedthat the mouthbars have an extensive lateral
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continuity based on well data and detailed logcorrelations (Fig. 19) and that production datasuggest that many of these sands areinterconnected, forming drainage areas of up to 20km2.
The initial reservoir architecture model was basedon these lithostratigraphic correlations in whichpetrophysically defined sandstones were correlatedif they occurred at the same stratigraphic levelrelative to a flooding surface datum (Fig. 21).However, several important discrepancies werefound during the 1990s: (1) full-scale waterflood onthe eastern flank of the field arrested productiondecline in some wells but in others failed to supportpressure and in seven wells water broke throughprematurely; (2) Kh derived from core data were twoto five times higher than those derived from welltests; (3) connected STOIIP was less than thecalculated STOIIP, suggesting that significantvolumes of oil may have been bypassed; and (4)some wells produced far more oil than theircalculated connected STOIIP whereas othersproduced far less, suggesting the originalconnectivity model was wrong (Ainsworth et al.,1999).
Therefore, a new model was developed for the DMember of the Lan Krabu in Sirikit West using achronostratigraphic correlation (Figs. 21 and 22)based on observations on analogous modern andancient mouthbar deposits and incorporating newwell and 3-D seismic data. In the correlation goodquality, petrophysically defined sandstonesdeposited on the upper parts of the mouthbar wereconsidered to grade down the depositional dip(estimated to be 0.5°) into thinly (2-15 cm)interbedded sandstones and shales, known asheterolithics, that represent the toe sets of theadvancing mouthbars (Ainsworth et al., 1999)(Fig. 22). Sandstones in the heterolithics are toothin to be properly resolved using low- resolution,conventional, downhole logs but can be seen incores and their presence in wells can be inferredfrom small inflections on GR, CFD and CNL logs.The grid cells used in the model were 25 x 25 x 0.2
m; their low height was selected to preserve thedepositional dips of discrete mouthbar sands.Petrophysical parameters were derived from logsand stochastically sampled core data. The modelwas scaled up to represent a single mouthbarparasequence. The flow model assumed an oil-filled reservoir with solution gas expansion as thenatural drive mechanism. Results of the simulationshowed that the lithostratigraphic-based model hasa 2.6% higher recovery factor than a chrono-stratigraphic model, in both cases with onlypetrophysically defined sandstones beingperforated. If the heterolithic sections wereperforated using the chronostratigraphic model, theabsolute recovery factor was increased by 1.7%relative to the same model without perforatedheterolithics.
Fractured basement reservoir in main Sirikit hasbeen successfully modeled using three faults, thetop pre-Tertiary seismic horizon and FMS logs fromthree wells (Smit 1999).
The typical thickness of stacked, fluvial channelsandstone bodies in the Lower Pradu Tao in Sirikit-D block, Sirikit West and Thap Raet Fields is inthe range 10-30 m. In the Upper Pradu Tao thebodies are less well connected and are 5-10 mthick. Sandstone bodies in the Lower Yom aretypically 2-5 m thick and isolated. Thap Raet andSirikit West have more complex architectures andfluid distributions, with multiple stacked oil columns,than Sirikit-D (Chuenbunchom et al., 2003).
The reservoirs in Sirikit West and Thap Raet arecompartmentalized by faults that are both sealingand partly sealing. Downhole logs and pressuretests indicate that there are multiple hydrocarboncolumns with multiple, stacked fluid contacts (Walshet al., 2001).
Reservoir Properties
Sandstones in the Lan Krabu Formation are veryfine-grained to coarse and pebbly (Flint et al., 1989)and are compositionally immature, containing
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common feldspar and metamorphic rock fragments.Reservoir quality declines with increasing burialdepth in all reservoirs and economic basement is at~2500 m (Brooks, 1987). Secondary porosity hasbeen formed by dissolution of feldspar and lithicfragments. Other diagenetic modifications includedthe formation of calcite, siderite and kaolinitecements. Variations in reservoir quality are largelycontrolled by differences in grain size because bothchannel and mouth-bar sands have similarmineralogy, other textural characteristics anddiagenetic history (Flint et al., 1988).
Reservoir quality is very variable in the Lan Krabuthroughout the main Sirikit Field (e.g., Fig. 23). Aporosity versus permeability cross-plot for threewells in the main field (Fig. 24) shows: (A) anoverlap between the values from themouthbar/continuous sandstones and the channel/discontinuous sandstones; (B) values from thechannel sandstones are closely clustered at thehigh end of the range whereas those from themouthbar sandstones show a wider range to lowervalues, reflecting the presence of finer grained andmore argillaceous rock types in the latter; (C) arelatively high porosity cut-off (e.g., 17.5%, Walsh etal., 2001) for net sand definition, if a conventional 1mD permeability cut-off is employed; and (D) netsands typically have porosities in the range 21-30%and permeabilities in the range 30-2000 mD.
The N:G ratio of the reservoir members varies from0.05 to 0.37 (Fig. 23, Table 1), across the mainSirikit Field, depending on depth and reservoirfacies. The K Member, the most productive in thefield, has N:G ratios of 0.25 in deltaic sands and0.05-0.15 in thin-bedded mouth-bar and floodplainsands (Flint et al., 1989).
Hydrocarbon saturations have been derived mainlyfrom capillary pressures rather than from resistivitylogs. This is because it is difficult to derive reliablesaturations from resistivity logs run throughintervals of thinly interbedded sandstones andshales, as found in the Lan Krabu (Walsh et al.,2001).
Reservoir properties for the Yom and Pradu TaoFormations in the Sirikit-D block, Sirikit West andThap Raet Fields (Table 2) and core analysis datafrom Sirikit West (Fig. 25) indicate that: (A)average porosities range from 16% to 28% and themaximum porosity is ~33%; (B) permeabilities aretypically in the range from 10 mD to several hundredmillidarcies and maximum values are >1 D; and (C)N:G ratios are very variable (0.15-0.7). In additionthe best-fit line for reservoir D (Fig. 25) shows thepotential for using a lower porosity cut-off (~13%)for net sand definition locally. Sirikit-D has the bestreservoir quality and the least complicated geologyof these three areas (Chuenbunchom et al., 2003).The analysis of NMR logs has confirmed theirreducible water saturations derived from coreanalyses and has increased the operator’sconfidence in the maximum hydrocarbonsaturations that have been assumed for thereservoirs in Sirikit West (Walsh et al., 2001).
Production Engineering Analysis
Volumetric figures are somewhat confused becauseauthors do not always make clear whether they arereferring to the main Sirikit Field alone or to theGreater Sirikit Area which includes satellite fields.On discovery it was thought that the main SirikitField may have a STOIIP as high as 1 BBO(Brooks, 1987). As the field’s complexity wasrecognised and became better understood,volumetric estimates were reduced to 312 MMBO inplace and 34 MMBO recoverable (Brooks, 1987)and 350 MMBO in place and 41 MMBO recoverable(Flint et al., 1988). These figures indicate recoveryfactors of 11-12%. In the late 1990s significantlyhigher STOIIPs and URRs were reported but thesemay include satellite fields, e.g., 791 MMBO inplace, 133 MMBO recoverable (Schaafsma andPhuthithammakul, 1997) and 800 MMBO in place(for the ‘Sirikit oil field’, Ainsworth et al., 1999).Sirikit West has a STOIIP of 34 MMBO (Ainsworthet al., 1998). Shell (2001) reported proved reservesof 126 MMBO for the S1 concession. The mostrecent URRs, for the Greater Sirikit Area, are 148MMBO and 250 BCFG (OGJ, 2001a).
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The oil has an API gravity of 36-40o and its high (15-20%) wax content, low GOR and lack of sulphur aretypical of oils derived from lacustrine source rocks(Sladen, 1997). Gas-cap expansion, weak solution-gas drive and weak aquifer support are the primaryproduction mechanisms; aquifer support is weakdue to reservoir compartmentalization and lowpermeability in the water leg.
Field development and pilot production commencedin 1982, following testing of the discovery well. Fiveappraisal wells were drilled during 1982, whichhighlighted the complex nature of the reservoir.Field development took place in stages andadditional areas were exploited, as the field wasbetter understood. Shortly after productioncommenced, reservoir pressure dropped from aninitial value of 2760 psi to below the bubble point(2360 psi) and as a result GORs increased and oilproduction fell. GOR limits were set for eachreservoir sequence and high GOR wells were shut-in. An intensive drilling campaign boostedproduction rate until it reached a plateau rate of~20,000 BOPD was achieved in 1985, despitesome setbacks (Brooks, 1987), and this wasmaintained until 1993 (Fig. 26).
A pilot water injection programme was initiated inthe late 1980s. This was successful and a full-scalewaterflood was implemented in the main field in1995 (Ainsworth et al., 1999) at a cost of US$33Mand this helped to reverse the decline in production(Fig. 26). Initially 11 wells injected 40,000 BWPDinto the reservoir, primarily in the relatively unfaultedareas of the field. A direct injection method wasadopted, with water being sourced from andinjected within the same well. Water is drawn fromthe Pratu Tao Formation aquifer at wellheadpressures of 800-1200 psi, using electricsubmersible pumps (ESPs) and injected directlyinto the Lan Krabu Formation in the same wells(Finley et al., 1996).
By 1998 >130 wells had been drilled (Ainsworth etal., 1998) and the well spacing was 400-650 m in
1999 (Ainsworth et al., 1999). In 2001, the fieldsuffered a rapid drop in pressure and the averageproduction from the Greater Sirikit field fell to 21,760BOPD from an expected 24,900 BOPD (OGJ,2001b) and in the same year Shell announced aplan to redevelop the field and explore the S1licence, at a cost of US$ 360M. Shell planned todrill 132 infill wells on Sirikit, together with over 50exploration, appraisal, gas production and satellitedevelopment wells by 2007. Satellite field tie-backsand developments include the Nang Makhamsatellite NW of Sirikit producing 1500-2000 BOPDand waterflood programs at the Thap Raet andWest Sirikit satellite fields (OGJ, 2001a).
Production from the Yom and Tao Pradu Formationsin Sirikit-D, Sirikit West and Thap Raet Fieldsstarted in 1997, and in 2003 8500 BOPD was beingproduced. The oil is mostly undersaturated and hasAPI gravities of 36-40° (Chuenbunchom et al.,2003). Initial production from Sirikit-D (Fig. 27) wasfrom three wells and the primary recovery factorwas expected to be 22%. Water injection started inJanuary 2000 from an injector (LKU-CC02) locatedin the south of the field (Fig. 28A). Well LKU-D14located to the north of the crest benefitted most,with oil production increasing from ~353 to ~663BOPD (Fig. 29). Well LKU-CC01 on the crest of thestructure began production in April 2002 afterpressure support had built up and led to asubstantial increase in production for the field from~844 to ~2677 BOPD (Fig. 27). With carefulmonitoring, modeling and recompletions theultimate recovery factor is expected to be 40%(Chuenbunchom et al., 2003).
In Thap Raet Field, which is more complex thanSirikit-D, water injection was commissioned in 2001(Fig. 30). However a rapid decline in injectivity wasobserved and this was eventually tackled byartificially fracturing the reservoir. Water injectionwas responsible for 85% of oil production in the firsthalf of 2003 and it is expected to increase theultimate recovery factor from 14% to 36%(Chuenbunchom et al., 2003).
© C & C Reservoirs. All Rights Reserved.
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Production started in Sirikit West in 1985 and by1998 the field was producing 800 BOPD from fourwells (Ainsworth and Sankosik, 1998). Waterinjection under fracturing conditions was initiatedfollowing comprehensive modeling and simulationstudies that were necessary because of thecomplexity of the reservoir and uncertaintiesregarding the connectivity of the sand bodies, forexample (Chuenbunchom et al., 2003). Theultimate recovery factor is expected to increasefrom 15% to 31%, i.e., rather less than in Sirikit-Dand Thap Raet. The success of waterflood projectsin Sirikit West and Thap Raet was partly responsiblefor an 8.8% increase in oil reserves for the GreaterSirikit Area to 148 MMBO at the end of 2000 (OGJ,2001a). It was hoped that the waterfloodprogramme together with new discoveries insatellite fields could maintain production at 24,000BOPD and 60 MMCFGPD until 2010 (Alexander’sGas and Oil Connections, 1999b), however, in 2004and 2005, average production had declined to justover 17,000 BOPD (Fig. 26).
As a result of detailed reservoir modeling, zones ofbypassed oil have been identified together with oil
bearing thin-bedded sands below seismic and logresolution. Wells are being recompleted to tapthese oil reserves. Reperforation and recompletionhave increased recovery factors to 28% in somereservoir compartments and raised daily productionby 5% (Ainsworth et al., 1999b) above the basecase.
Production from fractured basement has beenattempted from three wells. The most successful,on the Central Sirikit High in the main Sirikit Field,has been in production since 1991 but another wellwatered out rapidly so was shut-in and a third onlyproduced water (Smit, 1999).
Oil is transported from the field in a fleet of roadtankers to the railway terminal at Bung Phra, 55 kmaway (Brooks, 1987). From there it is taken to theBangchak refinery near Bangkok. A gas separationand processing plant was built in 1990, close to thefield at Kamphaeng Phet. It handles 40 MMCFGPDand 700 BCPD and feeds gas to a local electricitypower station. LPG is extracted from theassociated gas and in early 1999 averageproduction was 310 tons per day (OGJ, 1999a).
© C & C Reservoirs. All Rights Reserved.
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Ainsworth, R.B., Sanlung, M., and Duivenvoorden, S.T.C., 1999, Correlation techniques, perforation strategies,and recovery factors: An integrated 3-D reservoir modeling study, Sirikit Field, Thailand: AAPG Bulletin, v. 83,p. 1535-1551.
Ainsworth, R.B., Saanlung, M., Duivenvoorden, S.T.C., Colleran, P.J., and Mäkel, G.H., 1998, Impact ofmouthbar correlation techniques on recovery factors, Sirikit Field, Thailand. An integrated 3-D reservoirmodeling approach: AAPG Annual Convention, Salt Lake City, extended abstracts A12, 3 p.
Ainsworth, R.B., and Sankosik, H., 1998, 3-D reservoir modelling of the Sirikit West Field, Phitsanulok Basin,Thailand: Proceedings Asia Pacific Conference on Integrated Modelling for Asset Management, Kuala Lumpur,SPE Paper 39737, p. 137-147.
Alexander’s Gas and Oil Connections, 1999a, E & SE Asia company news, Thai Shell offshore drilling on hold:v. 4, no. 12: www.gasandoil.com/goc/company/cns92761.htm.
Alexander’s Gas and Oil Connections, 1999b, E & SE Asia company news, Shell to bid for more onshore andoffshore blocks in Thailand: v. 5, issue 16: www.gasandoil.com/goc/company/cns03629.htm.
Brooks, J., 1987, Development of the Sirikit oil field, Thailand, in Horn, M.K., ed., Transactions of the 4thCircum-Pacific Energy and Mineral Resources Conference, Singapore, p. 35-42.
Chuenbunchom, S., de Bruijn, G., Indran, D., and Akrapipatkul, P., 2003, Waterflooding in low N/G fluvialenvironment-Thai Shell experience: International Improved Recovery Conference, Kuala Lumpur, SPE Paper84922, 7 p.
Finley, D.B., Chong, K.K., Van Dolemen, M.L., and Kaweeyanun, P., 1996, Multiple frac-pack stimulations ofdeviated, high-permeability water-source wells: Proceedings Asia Pacific Oil and Gas Conference, Adelaid,SPE Paper 37013, 9 p.
Fletcher, G.L., 1982, Oil and gas developments in the Far East in 1981: AAPG Bulletin, v. 66, p. 2360-2482.
Fletcher, G.L., 1983, Oil and gas developments in the Far East in 1982: AAPG Bulletin, v. 66, p. 1884-1947.
Fletcher, G.L., and Soeparjadi, R.A., 1984, Oil and gas developments in the Far East in 1983: AAPG Bulletin,v. 66, p. 1622-1677.
Flint, S., Stewart, D.J., Hyde, T., Gevers, E.C.A., Dubrule, O.R.F., and van Riessen, E.D., 1988, Aspects ofreservoir geology and production behavior of Sirikit Oil Field, Thailand: an integrated study using well and 3-Dseismic data: AAPG Bulletin, v. 72, p. 1254-1269.
Flint, S., Stewart, D.J., and van Riessen, E.D., 1989, Reservoir geology of the Sirikit oilfield, Thailand,lacustrine deltaic sedimentation in a Tertiary intermontane basin, in Whateley, M. K.G., & Pickering, K. T., eds.,Deltas: sites and traps for fossil fuels: Geological Society, London, Special Publication, no. 41, p. 223-237.
© C & C Reservoirs. All Rights Reserved.
KEY REFERENCES
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Knox, G.J., and Wakefield, L.L., 1983, An introduction to the geology of the Phitsanulok Basin: Conf. Geol. Min.Res. Thailand, 9 p.
Lawwongngam, K., and Philp, R.P., 1991, Geochemical characteristics of oils from the Sirikit Oilfield,Phisanulok Basin, Thailand: Chemical Geology, v. 93, p. 129-146.
OGJ, 1982-99, Worldwide production: Oil & Gas Journal, v. 80-97.
OGJ, 1999a, Thailand E & P gets new, revitalized participants: www.ogj.com/display_article/22746/7/ARCHI/none/none/1/Thailand-E&P-gets-new,-revitalized-participants/
OGJ, 1999b, Shell plans oil production increase in Gulf of Thailand: www.ogj.com/display_article/42741/7/ARCHI/none/none/1/Shell-plans-oil-production-increase-in-Gulf-of-Thailand/.
OGJ, 2001a, Thai Shell boosts reserves at Sirikit field: online archive full ref not available, April 10, MP e-mailed 21 Nov.
OGJ, 2001b, Shell to begin pilot water injection project at Thai field: http://ogj.pennet.co/articles/web_article_display.cfm?ARTICLE_CATEGORY=DriPr&ARTICLE_ID=130807&x=y
Polachan, S., Pradidtan, S., Tongtaow, C., Janmaha, S., Intarawijitr, K., and Sangsuwan, C., 1991,Development of Cenozoic basins in Thailand: Marine and Petroleum Geology, v. 8, p. 84-97.
Polahan, P., 1986, Oil potential in the Gulf of Thailand: Proceedings of the 18th Offshore TechnologyConference, Houston, SPE Paper 5179, p. 255-259.
Thai Shell Exploration and Production Co., Ltd., 1999, Fact sheet, p. 1-3.
Schaafsma, C.E., and Phuthithammakul, S., 1997, Reservoir characterization helping to sustain oil productionin Thailand’s Sirikit Field: AAPG Bulletin, v. 78, p. 1161.
Shell, 2001, Thai Shell Exploration and Production Co. Ltd.: http://www.shell.co.th/English/aboutshell/business_thaishell.htm
Sladen, C., 1997, Exploring the lake basins of east and southeast Asia, in Fraser, A.J., Matthews, S.J., &Murphy, R.W., eds., Petroleum geology of southeast Asia, Geological Society, London, Special Publication, no.126, p. 49-76.
© C & C Reservoirs. All Rights Reserved.
KEY REFERENCES(continued)
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Smit, J., 1999, Oil recovery and fracture distribution in Basement reservoirs: European Association ofGeoscientists and Engineers 61st conference and Technical Exhibition, Helsinki, Paper 5-07, 4 p.
Walsh, R., Ramamoorthy, R., and Mohamed, A., 2001, Applications of NMR logging in synthetic oil-basedmuds in the Sirikit West Field, onshore Thailand: SPWLA 42nd Annual Logging Symposium, 14 p.
© C & C Reservoirs. All Rights Reserved.
KEY REFERENCES(continued)
© C & C Reservoirs. All Rights Reserved.
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TABLE OF FIELD PARAMETERS
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
1 - GENERALField nameLocationBasin name Basin typeOperatorHydrocarbon typeDiscovery year (well)Discovery well flow rateFirst productionCurrent statusNo. exploration and appraisal wells No. production wells (year)No. injection wells (year)Platforms/production centresElevation or water depth
2 - TRAPStructural settingTrap typeTiming of trap formationClosure mechanismsBasis for discoverySeismic databaseDirect hydrocarbon indicators (DHI)Depth to top payReservoir dipNo. of vertically separate HC poolsNo. of structural compartmentsVertical closure to spill pointOriginal hydrocarbon column heightAreal closure to spill pointField areaOriginal fluid contact
Current fluid contacts (date)
3 - RESERVOIRProducing formation (age)Depositional systemSandbody type (dominant)Sandbody type (secondary)Sandbody type (tertiary)Reservoir architecture/geometryFluid flow restrictions: macro-scaleFluid flow restrictions: meso-scaleFluid flow restrictions: micro-scaleNo. reservoir stratigraphic layersGross reservoir thicknessNet reservoir thicknessN/G ratioNet payLithologyPorosity typesCore porosityAir permeabilityProduction-derived permeabilityInitial water saturation
SIRIKITOnshore ThailandPhitsanulok BasinBally: 3122; Klemme: IIIBThai Shell Exploration and Production LtdLight oil and gas1981 (Lan Krabu LKU AOL 1)4400-4600 BOPD1982On production7127 (2005)NA8 clustersElevation: 59 m
Rift basinTilted fault-block in half-grabenMioceneDip-closed and fault-closedRegional studies, potential field data and seismic grid 3-D seismic data 1983-84NA1350 m TVDSS (Main field, K Member)10°Multiple Multiple NAOil: 86 m (K Member, main field); >200 m (L Member, main field) 12,000 ac (48.6 km2)14,000 ac (56.7 km2)Main field: widespread GOC: 1555 m TVDSS; K Mb OWC: 1641 mTVDSS; other ODTs and OWCs between 1930 and 2400 m TVDSS NA
Main reservoir in main field: Lan Krabu Fm (Miocene)Lacustrine, shorefaceMouth bar sandsChannel sandsNAWedge-shaped siliciclastic lobesSealing faultsShale interbeds, lateral facies changesCementation, compactionMain field: 5 minimumMain field: 540 m; 320 m (K); 190 m (L); 70 m (M)NA0.05-0.25 (K Member, main field)NASandstonePrimary intergranular mainly, secondary dissolution21-30% (net sand, main field)30-2000 mD (net sand, main field)NANA
© C & C Reservoirs. All Rights Reserved.
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TABLE OF FIELD PARAMETERS(continued)
4 - SOURCEFormation and ageLithologyDepositional systemTOCKerogen typeTime of hydrocarbon expulsion
5 - SEALFormation and ageLithologyDepositional systemThickness
6 - RESERVES AND PRODUCTIONOriginal volume in-placeUltimate recoverableCumulative production (date)Initial production rate (date)Max production rate (date)Current production rate (date)Current water-cut (date)Max prod rate per wellTypical prod rate per wellProductivity index
7 - HYDROCARBON COMPOSITIONAPI gravityViscositySulphur contentWax contentGas gravityGas contentCondensate yieldInitial GORFVFSaturation pressurePour point
8 - FIELD CHARACTERISTICSReservoir temperatureOriginal reservoir pressureCurrent pressure (date)Pressure gradientWater salinityNatural drive mechanismSecondary recovery method
Tertiary recovery methodImproved recovery methodRecovery factorProduction well spacingInjection rate (date)
Chum Saeng Fm (Miocene)Bituminous claystone and possibly coalsLacustrineTypically 1-2%; up to 17-40% in thin bedsType I & IIIPossibly started in Pliocene
Lan Krabu & Chum Saeng Fm (Miocene)Siltstone and claystoneLacustrineMain seal, for K reservoir: 200 m, others 300 m and 20-50 m
800 MMBO (1999, may include satellites)Whole S1 area: 148 MMBO; 250 BCF (2001)128 MMBO; 276 BCFG (2000)3,800 BOPD (1983)24,650 BOPD (1999)17,129 BOPD (2005), 60 MMCFD (2001)NA780 BOPD (1984)311 BOPD (avg. 1983-2005)NA
Main field: 39-40°; Sirikit-D, W, Thap Raet: 36-40° Sirikit-D, W, Thap Raet: 0.4-2.0 cp at reservoir conditionsNil15-20 wt.%NANANALowNAMain field: bubble point: 2360 psi @ 1830 m TVDSSMain field: 95 °F
Main field: 160 °F @ 1830 m TVDSSMain field: 2760 psi @ 1830 m TVDSSNAMain field: 0.445 psi/ftNASolution gas expansion, local gas cap expansion, limited aquifer supportWater injection: main field (1995); Sirikit D (2000); Thap Raet (2001,with frac); Sirikit West (2003, with frac)NoneInfill drillingOil: main field: 19%; Sirikit D: 40%; Thap Raet: 36%; Sirikit West: 31% Main field well spacing: 40-140 ac (400-650 m) (1999)Main field: 40,000 BWPD (1996); Sirikit D: ~7600 BWPD (2002); Thap Raet: ~4400 BWPD (early 2003)
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© C & C Reservoirs. All Rights Reserved.
TABLE OF FIELD PARAMETERS(continued)
Perforated casing; most wells completed in 2 or more reservoirs, withdual stringMain field: Lan Krabu Zones K, L, M, basement; Sirikit-D, W, ThapRaet: Pradu Tao and Lower YomNA
9 - COMPLETION PRACTICEType of completion
Interval perforated
Well treatment
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Seismic Stratigraphy
Seismic Reflector at
BaseMember-Sequence Lithology/depositional
environment Thickness (m) Net to Gross (%)
Reservoir Quality
K10 E10 Chum Saeng seal Lacustrine shales, thin sands 20 5 Poor
K20 E20 Main oil reservoirSheet sands, mouthbars, rare
channel sands, floodplain claystones
60-80 25 Good
K30 E30 Lacustrine shale Isolated channel sands, floodplain claystones 60-100 15 Poor
K40 E40 Lacustrine sands and shales Thick mouth bar sands 80-90 25 Good
E40-L Upper interval seal Open lacustrine shales 1 NA Poor
L RSVR High amplitude reservoir Coarsening-upward, regressive sequences and channel sands 190 NA Good
M RSVR Basal reservoir 70-80 Poor-moderate
Table 1 - Reservoir stratigraphy, lithologies, thickness, net:gross ratios and reservoir quality, Sirikit Field (Flint et al., 1988).
©C & C Reservoirs. All Rights Reserved.
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©C & C Reservoirs. All Rights Reserved.
Table 2 - Reservoir properties of the Pradu Tao and Yom Formations in Sirikit D, Thap Raet and Sirikit West Fields (Chuenbunchom et al., 2003).
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10 km0
DongChat Boundary
Fault
Western
BoundaryFault
MaeNamNan
Uttaradit Fault
AD1 Pru KrathiamBO1
NongKhaem
Thap RaetM
aePing Fault
100°E
17°N
16° 30'
S1 CONCESSION
OIL
GAS
CONDENSATE
MAJOR FAULT
THAILANDCAMBODIA
V I ET
NA
M
C H I N A
MYANMAR
GULFOF
THAILAND
AreaEnlarged
W. Sirikit
SIRIKITFIELD
N
Fig. 2
E. Sirikit
Figure 1 – Location map of the Sirikit Field, Phitsanulok Basin, Thailand (STPC 1999).
© C & C Reservoirs. All Rights Reserved.
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N
0 2 km
SIRIKITWEST
THAPRAET
SIRIKITD
SIRIKITMAIN
Figure 2 – Map showing location of satellite fields relative to the main Sirikit Field and faults (Chuenbunchomet al., 2003). For location, see Figure 1.
© C & C Reservoirs. All Rights Reserved.
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AA'
AYUTTHAYABASIN
N
97°95° 99° 101° 103° 105°
97°95° 99° 101° 103° 105°5°
7°
9°
11°
13°
15°
17°
19°
21°
5°
7°
9°
11°
13°
15°
17°
19°
21°
Myanmar
Laos Vietnam
CambodiaA n d a m a n
S e a
Vietnam
T H A I L A N D
MalaysiaIndonesia
Cenozoic basins
PHITSANULOKBASIN
PHETCHABUNBASIN
MAESOD
BASIN
SUPHANBUR
BASIN
KAMPHAENGSAENBASIN
FANGBASIN
NANGBUA
BASIN
BANGKOK
SIRIKITFIELD
G u l f o fG u l f o fG u l f o f
T h a i l a n dT h a i l a n dT h a i l a n d
SAKHONBASIN
0 100 km
Hainan
HongKong
C H I N A
B U R M A
VIETNAM
T H A I L A N D
LAOS
I N D O N E S I A
BRUNEI
C A M B O D I A
Singapore
Palawan
Nantuna Besar
B O R N E O
Belitung
S U M AT R A
J a v a
Bangka
ANDAMAN
SEA
S O U T H
C H I N A
S E A
Gulf ofThai land
J A V A S E A
100° 110°
10°
0°
10°
20°
0 500 1000 km
M A L AY S I A
Figure 3 – Cenozoic basins in Thailand (Polachan et al., 1989). Basins formed in the Oligocene and arepredominantly north-south trending half grabens. See Figure 5 for cross-section A-A'.
© C & C Reservoirs. All Rights Reserved.
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Mae Ping Fault Zone
Three Pagoda Fault Zone
Red River Fault Zone
TibetanPlateau
Extension
Compression
C H I N AI N D I A
KALIMANTAN
S o u t hC h i n a
S e a
A n d a m a nS e a
Indian Ocean Plate80° 100°
0°
20°
40°
H i m a l a y a s
Subduction zoneSpreading ridgeStrike-slip faultOceanic crust
Uttara
ditFa
ult Zo
ne
Ranong
Fault Z
one
Thai-MalayMobile BeltShan-ThaiIndo China
PHITSANULOKBASIN
CompressionN
Figure 4 – Location of the Phitsanulok Basin relative to major strike-slip faults and other regional tectonicelements (Polachan et al., 1991).
© C & C Reservoirs. All Rights Reserved.
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N
AA'
PHICHIT
PHITSANULOK
SJKHOTHAI
TSEPCO STBLOCK40 km0 20
PING FMFLUVIATILESAND, GRAVELMINOR CLAY
YOM FMFLUVIATILE SANDSTONEMINOR CLAY
PRATU TAO FMALLUVIAL PLAINCLAY, MINORFLUVIATILE SANDSTONE
LAN KRABU FM / CHUM SAENG FMFLUVIO - LACUSTRINECLAYSTONE, SANDSTONE
1000
2000
3000
0
GENERALISEDSTRATIGRAPHYPRATU TAO-A1
Dep
th (
m)
TAPHAN HINBASEMENT
BLOCK
L. MIOCENE? OLIGOCENE
SUKHOTAHAIDEPRESSION
KHAOLUANG
BASEMENTBLOCK L - M
MIOC.
M MIOCENE
NONG BUA
FM
KHIRI MATFM
PRATUTAOFM
PRATU
TAOFM
U MIOCENE
RECENTPLIOCENE
PING FM
YOM FM
BAN RAKAMHIGH
EASTERN FLANK
KRABU
FMLAN
CHUM
SAENG
FM
SARABORFM
PALEOZOIC
KHAOLUANG
WE
ST
ER
NB
OU
ND
AR
YF
AU
LT
2
1
0
3
4
5
6
7
8
2
1
0
3
DE
PT
H (km
)
10 km0 5
MESOZOIC
KHAOSAM WAIPHITSANULOK
PRATU TAOA1, 2SIRIKIT
projected 25 km from south
A'WA
DE
PT
H (
km)
E
Figure 5 – W-E cross-section through the Phitsanulok Basin, showing the asymmetric half graben, Western Boundary Fault and eastwards pinch-out ofsedimentary units (Flint et al., 1988). See Figure 3 for the location of section.
©C & C Reservoirs. All Rights Reserved. © 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of
American Association of Petroleum Geologists.
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N
FAULTZONE
RANGONG
U T TA R A D I TFA U LT
ZO NE LAOSM
YAN
MA
R
MA
E P
I NG
F AU
L T Z ON
E
THR
EEPAG
ODA
FA U LT Z O N E
CH
AD
PH
RA
YA
BA
SI N
Bangkok
G u l f o fT h a i l a n d
A n d a m a n
S e a
15° N
100° E95° 30’ E
CHA I NATR I DGE
BA
SI N
PH
I T SA
NU
LOK
MO
ULM
E I NB
AS
I N
KH
OR
AT
PLA
TE
AU
PE
TC
HA
BU
MG
RA
BE
N
T H A I L A N D
80 km0 40
SIRIKITFIELD
COMPRESSION
COMPRESSION
EXTE
NSIO
N EXTENSION
UFZ
MPFZ
TPFZ
TRANSTENSIONAL DEXTRAL SHEAR
CENTRAL THAILAND
Figure 6 – Location of the Phitsanulok Basin relative to the Uttaradit and Mae Ping fault zones(Flint et al., 1988).
© C & C Reservoirs. All Rights Reserved.
© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
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l
l
l
l
N
99°53'27.4"E 99°54'51.8"E99°52'03.0"E99°50'38.6"E
16°41'07.4"N
16°39'46.1"N
16°38'24.8"N
16°37'03.4"N
16°35'42.1"N
2 km10WELLSDRILLINGCLUSTERS
19001900
1700
1800
19001900
2000
1800
1900
1900
1700
1800
18001900
1800
1800
1700
1700
1800
1700
18001600
1600
1600
1700
1900
1900
2000
1900
2000
1800
B02
B01
E02E08
E09
1781
19011826
1850
E05
E06
E01
E03A02
R1742
1721 19071826
E07
E
E04 K02
C02
C01C
1818
A
A01
R01
1772
18121661
C03
D03D01
C04
D021772
17501690
D
K04F01 F02
K03
F031675
1857
F 1857
1881
K01K
1934
L03
L06
L02
1816
1776
17681733L04
P01P1764
G02807
DISCOVERYWELL
B B'SEISMIC LINEFigs. 8 and 9
C.I. : 100 m TVDSS
L
STRIKE-SLIP FAULT
NORMAL FAULT
Figure 7 – Top L Member depth-structure map for main Sirikit Field (Flint et al., 1988).
© C & C Reservoirs. All Rights Reserved.
© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
25
FAR
EAST
SIRIKIT
FIELD
EVALU
ATION
REPO
RT
TH
AILAND
- MIO
CENE
LAN
KRABU
FM
RESERVO
IR
240 260 280 300 320 340 360 380 400 420 440 460 480 500 520 540 560
1.0
2.0
A01 A02 R01 (proj.) E03 (proj.) E07 (proj.)EastWest
TOPSEAL
K
BASE-MENT
1 km0
1.0
2.0
TWT
(sec
) TWT (sec)
L
Figure 8 – W-E 3-D line 346 used for interpretation in Figure 9 (Brooks, 1987). See Figure 7 for location of the section.
©C & C Reservoirs. All Rights Reserved.
26
FAR
EAST
SIRIKIT
FIELD
EVALU
ATION
REPO
RT
TH
AILAND
- MIO
CENE
LAN
KRABU
FM
RESERVO
IR
500
1000
0
1500
2000
2500
3000
DE
PTH
(m
TV
DS
S)
R01(proj.)A01 / A02
BW
B'E
MAIN SEAL
MAIN SEAL
LOWER CLAY
KK
LL
KL
PRE-TERTIARY
BASEMENT
ODT 2005
GOC 1555OWC 1641
OWC 1930
500 m0
GAS OIL SEAL RESERVOIR BASEMENT
MM
E03(proj.)
E07(proj.)
Figure 9 – Geoseismic section based on W-E 3-D seismic line 346 shown in Figure 8, showing main reservoirs, pools, fluid contacts, seals and faults withinthe main Sirikit Field (Brooks, 1987). See Figure 7 for location of the section.
©C & C Reservoirs. All Rights Reserved.
27
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
SANDS/GRAVELS WITH ASSOCIATED CLAYSSands, clear, white, coarse grained,occasionally gravel.
Gravels, variegated, lithic
Clays, varicoloured, sandy, silty
SANDS/CLAYS
Sands, clear, white, coarse grained,occasionally gravel.
Clays, varicoloured, sandy, silty
SAND (STONES)/CLAY (STONES)
Sand (stones), clear, white, fine-coarse grained
Clay (stones), redbrown, varicoloured,sandy, silty
CLAYSTONES AND SILTSTONES/SANDSTONES
Claystones and siltstones, grey, silty,occasionally gastropod-bearing andcarbonaceous
Sandstones, clear, white, grey, fine-mediumgrained, thinly bedded
CLAYSTONES
Claystones, redbrown, occasionally grey tovaricoloured, with minor coarse-fine lithicsandstones
Fluvial &EphemeralLacustrine
Lacustrine&
Fluviolacustrine
EphemeralLacustrine& Fluvial
Fluvial
Alluvial Fan&
Alluvial Plain
D E S C R I P T I O N ENVIRONMENT
SO
UR
CE
& R
ES
ER
VO
IR
FIGURE13
MESOZOIC - PALEOZOIC CLASTIC, CARBONATE,
VOLCANICLASTIC IGNEOUS, AND METAMORPHIC ROCKS
LITHOLOGYTH
ICK
NES
S(U
P TO
)
FOR
MAT
ION
AG
E
1,30
0 m
1,60
0 m
2,20
0 m
2,20
0 m
1,20
0 m
SARA
BOP
-NO
NG B
UALA
N KR
ABU
-CH
UM S
AENG
PRAT
U T
AOYO
MPI
NG
LATE
MIO
CENE
-RE
CENT
MID
DLE
MIO
CENE
- LA
TE M
IOCE
NEEA
RLY
MIO
CENE
-M
IDDL
E M
IOCE
NEO
LIG
OCE
NEEA
RLY
MIO
CENE
PRE-TERTIARYBASEMENT
Figure 10 – Stratigraphy of the Phitsanulok Basin (Knox and Wakefield, 1983).
© C & C Reservoirs. All Rights Reserved.
28
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
BS
M
P
LIS
L
UIS
K
MS
D
K1
K2
K3
K4
L1
L2
L3
L4
P1
P2
P3SAR
AB
OP
LA
N
K
RA
BU
0 1 2 3 4
Sand Bodye.g., mouth bar, channel
ParasequenceSub-MbrMbrFm
FOUND IN SIRIKIT WEST,NOT IN MAIN FIELD
KEY PRODUCING HORIZONS
UNDEVELOPEDDEEP RESERVOIRS
LOWER CLAY
INTERMEDIATE SEAL
MAIN CLAY
Figure 11 – Reservoir stratigraphy of the Lan Krabu and Sarabop Formations, Sirikit Field(Ainsworth et al., 1999), showing seals, sequences and parasequences.
© C & C Reservoirs. All Rights Reserved.
29
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
M8 M
M2 M
LM
L6 M
L5 M
L4 M
L3 M
L2 M
L1 M
KM
K4 M
K3 M
K2 M
K1 MK1
K2
K3
K4
L1
L2
L3
L4
L5
L6LOWERINTERSEAL
UPPERINTERSEAL
LOWERCLAY
ML
K
LAN
K
RA
BU
1950
2000
2050
2100
2150
1900
1850
1800
1750
1700
1650
1600
2401500
GAMMA RAY SONIC40
GAS AND OIL
OIL
OIL
SEISMIC MARKER
O.D.T. 2146 (2088.2)
FOR
MAT
ION
MEM
BER
RES
ERVO
IRU
NIT
SBD
IVIS
ION
Depth(m)
Sand
Figure 12 – Typical log for Sirikit Field (Brooks 1987), showing GR, DT, reservoir units, seals and oil and gas zones.
© C & C Reservoirs. All Rights Reserved.
30
FAR
EAST
SIRIKIT
FIELD
EVALU
ATION
REPO
RT
TH
AILAND
- MIO
CENE
LAN
KRABU
FM
RESERVO
IR
P I N G F M .
PRATU TAO FM.
CHUM SAENG FM.
NONG BUA FM.
SARABOP FM.
LAN KRABU FM.
YOM FM.
SARABOP FM. KHOM FM.
L. MIO.
PL.
Q
OLI
GO
-CE
NEM
IOC
EN
EEA
RLY
MID
DLE
K
LM
ALLUVIAL FAN
ALLUVIAL PLAIN
DELTA PLAIN
PROTO-LAKE/FLOOD PLAIN
OPEN LAKE
FAN DELTA
LACUSTRINE DELTA
VOLCANICS
SOURCE
OIL RESERVOIR
SIRIKIT FIELDNorthSouth
Figure 13 – Summary of the stratigraphy of the Phitsanulok Basin along a S-N section, including the Sirikit Field (Ainsworth et al., 1999). Note the interfingering of the source rocks of the Chum Saeng and reservoirs of the Lan Krabu Formations .
©C & C Reservoirs. All Rights Reserved.
© 1999 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
31
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
A
C1C3
D E
A
C1C3
D E
N
0 1 km
ProducerInjector
Figure 14 – Structure map for Sirikit West. Depths and contour interval are not stated but the crest is at ~1980m TVDSS. The eastern fault was active during deposition of the reservoir intervals and is referred to as the
main boundary fault or W60 fault complex (Chuenbunchom et al., 2003).
© C & C Reservoirs. All Rights Reserved.
32
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
N
0 1 km
420
380
340
300
260
220
470410350290
y - coordinate
x - coordinate
E09E02
E08
E05E06
E03
E01
A 01 E07
E04K02
K05
C01
C03
K04
F03
D01F01
K01
K03
F02L01
L03
L02L04
Figure 15 – Seismic amplitude map of Sirikit for an horizon 36 msec TWT above the top of member L of the LanKrabu Formation. The high amplitudes (orange) indicate the presence of a ~16 m-thick sandstone wedge in
the Upper Intermediate Seal (UIS) in the NW of the main field (Flint et al., 1988).
© C & C Reservoirs. All Rights Reserved.
© 1988 American
Association of Petroleum Geologists. All rights reserved. Reprinted with permission of
American Association of Petroleum Geologists.
33
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
Ping
Gas Yom Upper Yom (UYOM)
Oil Lower Yom (LYOM)
Oil Pradu Tao (PTO) Upper PTO (UPTO)
Gas Lower PTO (LPTO)
Oil
Chum Saeng (CS) Main Seal (MS)
Oil Lan Krabu (LKU) D
Gas Lan Krabu (LKU) K
Oil
Chum Saeng (CS) Upper Intermediate Seal
Oil Lan Krabu (LKU) L
Chum Saeng (CS) Upper Intermediate Seal
Oil Lan Krabu (LKU) M
Chum Saeng (CS) Upper Intermediate Seal
Oil Sarabop P
Oil Pre Tertiary (PTT) Basement
Rock Formation Member
Figure 16 – Summary of the occurrence of oil and gas in the Yom and Pradu Tao Formationsin Sirikit and satellite fields and in older formations (Chuenbunchom et al., 2003).
© C & C Reservoirs. All Rights Reserved.
34
FAR
EAST
SIRIKIT
FIELD
EVALU
ATION
REPO
RT
TH
AILAND
- MIO
CENE
LAN
KRABU
FM
RESERVO
IR
Levee
Marsh bar aggradation facies
Minor channel fill
Major channel fill
Mouth bar/sheet sands
Distal mouth bar
Open lacustrine
Levee onupperpart of simple
midchannel bar
SONICGAMMA RAY
SONICGAMMA RAY
overbank channels
SONICGAMMA RAY
Compositemid-channel bar
SONICGAMMA RAYSONICGAMMA RAY
Major channel
SONICGAMMA RAY
Top-underlyingdelta cycle
Coalescent(dissected) mouth
bars
Prodelta
OPEN LACUSTRINE
Note: no implied lateral scale
10
0
verticalscale(m)
Figure 17 – 3-D depositional model for Lan Krabu Formation: a highly constructive, lobate, lacustrine delta (Flint et al., 1988).
©C & C Reservoirs. All Rights Reserved.
© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
35
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
S1
CS
C3
S2S1
C3
S3
C1
C1C3C1
S2
S1
CSC3
CS
CS
C3
CS
C3
C1
10 m
0
TYPE 2COARSENING-UPWARD UNIT
CREVASSE SPLAY
TYPE 1COARSENING-UPWARD UNIT
OPEN LAKE
TRANSGRESSION
T
T
FACIES
API 10050 150 50GAMMA RAY SONIC ENVIRONMENTAL
INTERPRETATION
WELL LKUE - 07K UNIT
RESERVOIR FACIES
• VERTICAL STACKED LACUSTRINE AND DELTAIC SEQUENCES C1 - C3 CLAYSTONES, CS SILTSTONE, S1 - S2 SANDSTONE
Figure 18 – Reservoir facies and environmental interpretation in the K Member of Sirikit Field based on log and core analyses of well LKUE-07 (Flint et al., 1988).
© C & C Reservoirs. All Rights Reserved.
© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
36
FAR
EAST
SIRIKIT
FIELD
EVALU
ATION
REPO
RT
TH
AILAND
- MIO
CENE
LAN
KRABU
FM
RESERVO
IR
20 100
10050
soft hard
soft hard12050 soft hard
13050 soft hardsoft hard10040
soft hard12050soft hard11050
soft hard12050soft hard13550
soft hard11050GR Δt
GR ΔtGR Δt
GR Δt GR Δt GR Δt GR ΔtGR Δt
GR ΔtGR Δt
0
20
40
60
80
100
120
DE
PT
H (
m)
E2 E9E8E5E6E3E7E4K2K1
TOP L
SE NWC'C
K 2
K 1
E 4
E 7E 3
E 6
E 5E 8
E 2E 9
B 1
B 2
E 1
A 2A 1
R 1
C 2
C 1
C 3K 5
K 4F 3D 3D 2 (1)
C 4 (1)C 4
D 1
D 2
F 1
L 3
L 6
L 5
L 1F 2K 3
L 5 (1)
P 2
L 4
L 2
P 1
G 2
Q 1
2 km0
C
C'
PR
OG
DR
AD
I NG
DE
LT
A
CLAYSTONE
'HARD' CLAY
SANDSTONE
• LATERALLY CONTINUOUS MOUTH BAR SANDS - GOOD CORRELATION• CHANNEL SANDS POOR CORRELATION
Legend
PALEOCURRENTDIRECTION
N
Figure 19 – Correlation of sandstone bodies in the L Member across part of Sirikit Field using GR, DT and synthetic seismograms (Flint et al., 1988).
©C & C Reservoirs. All Rights Reserved.
© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
37
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
A
B
N
300 350 450400 500 550
300 350 450400 500 550200
250
300
350
400
450
200
250
300
350
400
450
y - c
oord
inat
e
x - coordinate
L sandsreservoir
K sandsreservoir
MainSeal
E 40
E 30
TOP L
E 20
E 10
TOP K
(truevertical)
1550
1650
1600
1700
1750
1800
1850
1900
1950
2000
API50 110m +-hsDEPTH
GAMMARAY SONIC REFL.
WELL LKU-03WIRELINE & SYNTHETIC LOG
E10 TO E20 ISOCHOREEXTRACTED FROM FIELD 3D SEISMIC SURVEY
50
44
39
33
28
22
17
11
6
0
(ms)
1 km0
UpperIntermediateSealU I S
K20
K30
K40
K10
Figure 20 – (A) Gamma ray and sonic logs, synthetic seismogram, seismic horizons and sequences for the Kand upper L Members in well LKU E-03 (Flint et al., 1988). (B) E10-E20 seismic isochron map for main Sirikit
Field extracted from 3-D seismic survey, showing the thinning of the main K20 reservoir interval towards the Nand NW (Flint et al., 1988). Map covers the same area as Figure 7.
© C & C Reservoirs. All Rights Reserved.
© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
38
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
A
B
C
D
Flooding shale - Datum
10-20 m
GRGR400-650 mNo Infill Required
Lithostratigraphic Correlation
Flooding shale - Datum
10-20 m
GRGR
Infill Required ?
Chronostratigraphic Correlation
Infill location ?Bypassed oil
Restricted aquifer support
Good reservoir quality Heterolithics Shale
Flooding shale - Datum
10-20 m
GRGR400-650 mEfficient Sweep
Lithostratigraphic Correlation
Flooding shale - Datum
10-20 m
GRGR
Chronostratigraphic Correlation
Injector Producer
Relatively Inefficient Sweep
Injector Producer
Perforations
2
1
Figure 21 – Comparison of (A) lithostratigraphic with (B) chronostratigraphic correlations showing also theconsequent differences in sweep efficiencies (C & D), the potential need for infill wells and the potential benefit
of perforating the heterolithics (Ainsworth et al., 1999).
© C & C Reservoirs. All Rights Reserved.
© 1999 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
39
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
NMM-A01 NMM-A01S1 NMM-A03
500 m 10 m
D-1
D-2
D-3
N S
A
NMM-A01 NMM-A01S1 NMM-A03
500 m 10 m
D-1
D-2
D-3
BFacies: Mouth bar Heterolithic Shale
LITHOSTRATIGRAPHIC MODEL LITHOLOGY
CHRONOSTRATIGRAPHIC MODEL LITHOLOGY
NMM-A01 NMM-A01S1 NMM-A03
500 m10 m
D-1
D-2
D-3
C CHRONOSTRATIGRAPHIC MODEL POROSITYSTOCHASTICALLY DERIVED POROSITY FROM CORE PLUGS
WELLS PROJECTED ONTO SECTION
N S
Porosity: 5-10% 11-19% 20-24%
Figure 22 – Vertical sections from a 3-D reservoir simulation model, Sirikit Field, showing (A) thelithostratigraphic model facies and lithology; (B) the chronostratigraphic model facies and lithology; and (C)the chronostratigraphic model with stochastically derived porosity from core plugs (Ainsworth et al., 1999).
© C & C Reservoirs. All Rights Reserved.
© 1999 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
40
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
20
0
40
60
80
100 m
K2-B
K2-C
K2-A
K1
0 0.14 0.3
0.21 0.3
0.21 0.05
0.17 0.05
NA NA
0.2 0.15Total
N:G
WELL A04-A K UNITCORE POROSITY AVERAGE
POROSITY
Figure 23 – Core and average porosity and net to gross ratio, K Member, well AO4-A, Sirikit Field,(Ainsworth and Sankosik, 1998).
© C & C Reservoirs. All Rights Reserved.
41
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
10,000
1000
100
10
1
0.1
0.010.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35
POROSITY
UN
STR
ESSE
D A
IR P
ERM
EAB
ILIT
Y (m
D)
Continuous Sands ~ Mouth Bar Sands- Large drainage area- Poorer reservoir quality- Lower decline rate
Discontinuous Sands ~ Channel Sands- Smaller drainage area- Good reservoir quality- Higher decline rate
Figure 24 – Porosity versus permeability cross-plot, with mouthbar and channel sandstones indicated, forthree wells (A-01, E-02 and F-01) in the main Sirikit Field (Flint et al., 1988).
© C & C Reservoirs. All Rights Reserved.
© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.
42
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
A
B
10,000.00
1000.00
100.00
10.00
1.00
0.10
0.01
Per
mea
bili
ty (m
D)
Porosity (%)
0.00 10.00 20.00 30.00 40.00
Reservoir B (2 wells)
Reservoir C (4wells)
Reservoir D (1well)
Fit to Reservoirs B & C (Prior to NMR Well 2)
Fit to Reservoir D
Figure 25 – Porosity versus permeability cross-plot for reservoirs B, C and D in the Yom and Pradu TaoFormations in Sirikit West Field (Walsh et al., 2001). Highlighted data (A): data from Reservoir D seems to lieon a different trend relative to the other reservoirs; (B): some anomalously high permeabilities in Reservoir B
may be due to poor sample preparation.
© C & C Reservoirs. All Rights Reserved.
43
FAR
EAST
SIRIKIT
FIELD
EVALU
ATION
REPO
RT
TH
AILAND
- MIO
CENE
LAN
KRABU
FM
RESERVO
IR
25,000
20,000
15,000
10,000
5000
0
Aver
age
Oil
Prod
uctio
n R
ate
(BO
PD)
1982 1984 19901986 1988 1992 1994 1996 1998 2000 2002 2004YEAR
Water injectionstarted inmain field
No data for 2002Data point was
interpolated
Figure 26 – Production profile for Sirikit Field and satellites (OGJ, 1981-2005).
©C & C Reservoirs. All Rights Reserved.
44
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
Apr-97 Sep-98 Jan-00 Jun-01 Oct-02 Mar-04
Gross Net NFA WI
NFA case
12,000
10,000
8000
6000
2000GR
OSS
AN
D N
ET P
RO
DU
CTI
ON
(BPD
)
0
4000
CC01crestal well
Started injection in Jan 2000
Figure 27 – Production profile for Sirikit-D block (Chuenbunchom et al., 2003).
© C & C Reservoirs. All Rights Reserved.
45
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
LKU-D13
A Sand
B Sand
C Sand
D Sand
E Sand
F Sand
LKU-D16 LKU-D14
ODT seen in Well
Block Boundaries
Expected OWC
LKU-D14
Potential FaultMODEL LIMIT
LKU-D16
LKU-CC01
LKU-D13
LKU-CC02
Future Injector?
(Up-Dip)NS LKU-CC01LKU-CC02
(Up-Dip)
(Injector)
A Sand
B Sand
C Sand
D Sand
E Sand
F Sand
ODT seen in Well
700 m 420 m 270 m
Jan '00 Injection intervalPerforated interval
0 1 km
A
B
N
Figure 28 – (A) cartoon map of Sirikit-D showing well locations relative to OWC, (B) cartoon cross-sectionshowing perforated intervals (Chuenbunchom et al., 2003).
© C & C Reservoirs. All Rights Reserved.
46
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
Mar-97 Jul-98 Dec-99 Apr-01 Sep-02 Jan-04
Gross Rate Net Rate BS&W
3000
PRO
DU
CTI
ON
RAT
E (B
PD)
4000
5000
2000
1000
0
Startedwater injection
in Jan '00
Watercut decreasedue to
water injectionsweep change
Watercut increasedue to
Interferencefrom LKU-CC01
100
80
60
40
20
0
BS&
W (%
)
Figure 29 – Production profile for well LKU-D14 in Sirikit-D (Chuenbunchom et al., 2003).
© C & C Reservoirs. All Rights Reserved.
47
FAR EAST
SIRIKIT
FIELD EVALUATION REPORT
THAILAND - MIOCENE LAN KRABU FM RESERVOIR
0
5000
Feb-98 Feb-99 Jan-00 Jan-01 Dec-01 Dec-02 Nov-03 Nov-04
GROSS NET WI
NFA case
4000
3000
2000
1000
GR
OSS
AN
D N
ET P
RO
DU
CTI
ON
(BPD
)
Gross and oil rateincrease due to
TRT-D04
TRT-B03 ESPQuit
(Mar-Aug 2002)
Started injectionin Oct '01
Figure 30 – Production profile for Thap Raet Field (Chuenbunchom et al., 2003).
© C & C Reservoirs. All Rights Reserved.