Field Evaluation Report Sirikit Field C&CReservoirs - CCOP

Field Evaluation Report

First compiled: February 2002Last modified: December 2009

– Far East –

Sirikit FieldPhitsanulok Basin, Thailand

© C & C Reservoirs. All Rights Reserved. C&CReservoirsthe analog company

© C & C Reservoirs. All Rights Reserved.

1

FAR EAST

SIRIKIT

FIELD EVALUATION REPORT

THAILAND - MIOCENE LAN KRABU FM RESERVOIR

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

2

FAR EAST

SIRIKIT



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


3

FAR EAST

SIRIKIT



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


4

FAR EAST

SIRIKIT



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


5

FAR EAST

SIRIKIT



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


6

FAR EAST

SIRIKIT



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


7

FAR EAST

SIRIKIT



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).


8

FAR EAST

SIRIKIT



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).


9

FAR EAST

SIRIKIT



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).


10

FAR EAST

SIRIKIT



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.


KEY REFERENCES

11

FAR EAST

SIRIKIT



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.


KEY REFERENCES(continued)

12

FAR EAST

SIRIKIT



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.


KEY REFERENCES(continued)


13

FAR EAST

SIRIKIT

TABLE OF FIELD PARAMETERS



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


14

FAR EAST

SIRIKIT



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)

15

FAR EAST

SIRIKIT




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

16

FAR

EAST

SIRIKIT

FIELD

EVALU

ATION

REPO

RT

TH

AILAND

- MIO

CENE

LAN

KRABU

FM

RESERVO

IR

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.

17

FAR

EAST

SIRIKIT

FIELD

EVALU

ATION

REPO

RT

TH

AILAND

- MIO

CENE

LAN

KRABU

FM

RESERVO

IR


Table 2 - Reservoir properties of the Pradu Tao and Yom Formations in Sirikit D, Thap Raet and Sirikit West Fields (Chuenbunchom et al., 2003).

18

FAR EAST

SIRIKIT



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).


19

FAR EAST

SIRIKIT



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.


20

FAR EAST

SIRIKIT



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'.


21

FAR EAST

SIRIKIT



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).


22

FAR

EAST

SIRIKIT

FIELD

EVALU

ATION

REPO

RT

TH

AILAND

- MIO

CENE

LAN

KRABU

FM

RESERVO

IR

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.

23

FAR EAST

SIRIKIT



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).


© 1988 American Association of Petroleum Geologists. All rights reserved. Reprinted with permission of American Association of Petroleum Geologists.

24

FAR EAST

SIRIKIT



ll

ll

l

ll

ll

ll

l

l

ll

ll

ll

l

l

l

ll

ll

ll

ll

l

l

l

l

l

l

l

ll

ll

ll

l

l

l

l

l

l

ll

l

ll

ll

l

l

ll

l

ll

ll

l

l

ll

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

l

ll

l

ll

ll

ll

ll

ll

l

ll

ll

ll

l

ll

l

l

l

ll

ll

l

ll

l

ll

l

ll

ll

ll

l

l

l

ll

ll

ll

ll

ll

l

l

l

l

l

l

ll

ll

ll

l

ll

l

ll

ll

l

l

l

l

l

ll

l

ll

l

l

l

ll

l

ll

ll

ll

l

l

l

l

l

l

ll

ll

l

l

ll

l

l

l

ll

ll

l

l

l

l

ll

ll

ll

ll

l

ll

l

ll

ll

ll

ll

ll

l

ll

ll

ll

ll

l

l

l

ll

ll

l

ll

ll

ll

ll

l

l

l

l

l

ll

ll

l

ll

l

ll

ll

l

l

l

l

l

ll

l

l

ll

l

l

l

l

l

l

l

l

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).



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.


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.


27

FAR EAST

SIRIKIT



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).


28

FAR EAST

SIRIKIT



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.


29

FAR EAST

SIRIKIT



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.


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 .



31

FAR EAST

SIRIKIT



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).


32

FAR EAST

SIRIKIT



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).


© 1988 American

Association of Petroleum Geologists. All rights reserved. Reprinted with permission of

American Association of Petroleum Geologists.

33

FAR EAST

SIRIKIT



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


Oil Lan Krabu (LKU) M


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).


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).



35

FAR EAST

SIRIKIT



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).



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).



37

FAR EAST

SIRIKIT



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.



38

FAR EAST

SIRIKIT



A

B

C

D

Flooding shale - Datum

10-20 m

GRGR400-650 mNo Infill Required

Lithostratigraphic Correlation


10-20 m

GRGR

Infill Required ?

Chronostratigraphic Correlation

Infill location ?Bypassed oil

Restricted aquifer support

Good reservoir quality Heterolithics Shale


10-20 m

GRGR400-650 mEfficient Sweep

Lithostratigraphic Correlation


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).



39

FAR EAST

SIRIKIT



NMM-A01 NMM-A01S1 NMM-A03

500 m 10 m

D-1

D-2

D-3

N S

A


500 m 10 m

D-1

D-2

D-3

BFacies: Mouth bar Heterolithic Shale

LITHOSTRATIGRAPHIC MODEL LITHOLOGY

CHRONOSTRATIGRAPHIC MODEL LITHOLOGY


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).



40

FAR EAST

SIRIKIT



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).


41

FAR EAST

SIRIKIT



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).



42

FAR EAST

SIRIKIT



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.


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).


44

FAR EAST

SIRIKIT



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).


45

FAR EAST

SIRIKIT



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).


46

FAR EAST

SIRIKIT



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).


47

FAR EAST

SIRIKIT



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).


Field Evaluation Report Sirikit Field C&CReservoirs - CCOP

Documents

Transcript of Field Evaluation Report Sirikit Field C&CReservoirs - CCOP