Oil Geochemistry of Eastern Indonesia (Peters Et Al., 1999)

7/28/2019 Oil Geochemistry of Eastern Indonesia (Peters Et Al., 1999)

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ABSTRACT

High-resolution geochemistry shows geneticrelationships among 27 crude oils from easternIndonesia and suggests the ages and paleoenviron-ments of their source rocks. Oils inferred to origi-nate from Tertiary and Triassic–Jurassic sourcerocks in the study occur north and south of 2°S lati-tude, respectively. Twenty oils mainly from Irian

Jaya and Sulawesi originated from Tertiary

marine marlstone source rocks that containedtype II/III kerogen deposited under suboxic condi-tions, probably the upper Miocene Klasafet Formation.

These low-sulfur oils show high oleanane, C2624-nordiacholestane, and pristane/phytane ratios,and 13C-rich carbon isotope compositions. Higholeanane and 24-nordiacholestane ratios are diag-nostic of Tertiary oils and source rocks. These oilsaccount for about 16% of the estimated ultimaterecoverable reserves in eastern Indonesia.

Five oils from Seram originated from Triassic– Jurassic marine carbonate source rock that con-tained type II kerogen deposited under anoxic con-ditions. These high-sulfur oils lack oleanane and

generally show low C26 24-nordiacholestane andpristane/phytane ratios. Low-sulfur Aliambata seepoil from Timor originated from type II/III kerogenin a more oxic, terrigenous-influenced marine clas-tic equivalent of this carbonate source rock. Thesesix oils account for only about 2%of the estimatedultimate recovery in the area.

Low-sulfur shallow oil from Miocene Kais reser-voirs in the Wiriagar field in Irian Jaya lacksoleanane,

1927AAPG Bulletin, V. 83, No. 12 (December 1999), P. 1927–1942.

©Copyright 1999. The American Association of Petroleum Geologists. Allrights reserved.

1Manuscript received June 16, 1998; revised manuscript received March25, 1999; final acceptance May 30, 1999.

2Mobil Technology Company, Box 650232, Dallas, Texas 75265-0232;e-mail: [email protected]

3Resource System Diagnostics, Box 4382, Jakarta 12043, Indonesia;e-mail: [email protected]

4Mobil Oil Indonesia, Jakarta Indonesia; e-mail: yJAKLNM1.JAK.MOBIL.COM5Pertamina, Jakarta Indonesia.We gratefully acknowledge Budiono and Mobil Oil Indonesia for

permission to release this paper and thank Ron Noble, Wally Dow, RoyEnrico, Jim Stinnett, and Asep Sulaeman for peer reviews of the draft. JohnZumberge, Brad Huizinga, and Lyle Henage provided useful discussions ofsamples and regional geochemistry. Cliff Walters, Mike Flagg, Connie Hellyer,Brock Toon, and Ruth Barrow completed analyses of the samples at the MobilTechnology Company geochemical laboratory. Mike Moldowan (BiomarkerTechnology, Inc.) assisted with mass spectrometry of the steranes.

Geochemistry of Crude Oils from Eastern Indonesia1

Ken E. Peters,2 Tom H. Fraser,3 Welly Amris,4 Budi Rustanto,5 and Eddy Hermanto5

is highly mature, and has undergone extensivemigration fractionation. This oil probably originat-ed from synrift-postrift Lower–Middle JurassicKembelangan Formation clay-rich shales that con-tained mixed type II/III kerogen deposited underoxic conditions. The huge gas reserves from thedeep Wiriagar field were not analyzed but probablyoriginated from Paleozoic source rocks. The shal-low Wiriagar accumulation accounts for about 5%and the deep Wiriagar accumulation accounts for

about 77% of the estimated ultimate recovery ineastern Indonesia.

INTRODUCTION

In the southeast Asia-Australasia region, total esti-mated ultimate recovery of petroleum amounts toabout 125 billion bbl of oil equivalent (BOE) [50billion bbl oil, 125 tcf (trillion ft3) gas] (Howes,1997). Petroleum systems in this large region arecontrolled by the major tectonic breakup of Gondwana in the Paleozoic and early Mesozoic.Our study area in eastern Indonesia (Figure 1) lies

between the dominantly Tertiary petroleum sys-tems on the Eurasian plate and the dominantlyPaleozoic–Mesozoic systems on the Indo-Australianplate. The affinities of many crude oils in the studyarea were uncertain prior to our work.

About one-half of the 38 basins in our easternIndonesian study area remain undrilled (Sumantriand Sjahbuddin, 1994), and many other basins arepoorly explored; nevertheless, significant amountsof oil and gas are produced from the Salawati,Bintuni, and Bula basins. Geologists have speculat-ed for many years that crude oils in easternIndonesia originated mainly from Jurassic source

rocks. Upper Jurassic marine source rocks generat-ed about 25% of the world’s oil and gas (Klemmeand Ulmishek, 1991). The Upper Jurassic sourcerocks of Australasia are generally not as prolific asother age-equivalent rocks (e.g., West Siberia, cen-tral Arabia, North Sea, Tampico, and Campeche).Howes (1997) estimated that only about 5% of thediscovered oil and gas reserves in southeast Asia-Australasia originated from Jurassic source rocks,but they are still significant sources for oil and gas.Examples include the Upper Jurassic Dingo Shale



1928 Geochemistry of Eastern Indonesia Crudes

F i g u r e 1 — M a p o f e a s t e r n I n d o n e s i a s h o w i n g s a m p l e l o c a t i o n s i n t h e S a l a w a t i a n d B i n t u n i b a s i n s

( d o t t e d b a s i n o u t l i n e s ) , t h e B u l a a r e a o n S e r a m , e a s t -

e r n S u l a w e s i , a n d T i m o r . S y m b o l s a t s a m p l e l o c a t i o n s s h o w g

e n e t i c r e l a t i o n s h i p s e s t a b l i s h e d b y

t h e s t u d y ( i n s e t ) . M o s t T e r t i a r y ( g r o u p s 2 a n d 3 ) a n d

T r i a s s i c – J u r a s s i c ( g r o u p s 1 a n d 4 ) o i l s o c c u r n o r t h a n d s o u t h

o f 2 ° S l a t i t u d e , r e s p e c t i v e l y . L o c a t i o n s f o r s a m p l e s f r o m M a t o a ( g r o u p

2 , I r i a n J a y a ) a n d

K S 9 0 1 6 ( g r o u p 4 , S e r a m ) a r e u n k n o w n . L o c a t i o n s f o r O i l s A ( e a s t e r n S u l a w e s i ) a n d B ( e a s t e r n S e r a m ) a r e p r o p r i e t a r y .

S U L A W E S I

I R I A N J A Y A

K L A L I N

J A Y A

C E N D R A W A S I H

A L I A M B A T A

M I N A H A K I

K O L O

B U L A

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T I M O R

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d a S e a

T i m o r S e a

M a k a s s a r S t r a i

t

I n d i a n O c e a

n

P a c i f i c O c e a

n

A r a f u r a S e a

F l o r e s S e a

M o l u c c a S e a

S O U T H W E S T O

A G L

P T .

P A T R I N D O

O

B I

G r

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1

2

3

4

W I R I A G A R

S A L A W A T I B A S I N

L I N D A

K A S I M

K A S I M B A R A T

K L A L I N

K L A M O N O

B I N T U N I B A S I N

W A L I O

“

W A L I D ”

E .

O N I N - 1

0 o

5 o S

1 0 o S

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S O U T H W E S T O



(Barrow-Dampier subbasin) and Flamingo Shale(Vulcan subbasin) in northwestern Australia(Bradshaw et al., 1997).

Although limited to only a few oil samples, tenHaven and Schiefelbein (1995) inferred at least threepetroleum systems in eastern Indonesia where thesource rocks consist of Tertiary marine carbonates,Mesozoic marine carbonates, and Mesozoic marinesiliciclastics. They found one Tertiary nearshoremarine carbonate oil on the east coast of Sulawesi(Banggai), one Tertiary nearshore marine carbonateoil and one Mesozoic marine clastic oil in the BintuniBasin, one Mesozoic marine carbonate oil on Seram,and one Mesozoic marine clastic oil on Timor.

For this study, 27 crude oil and seep samples werecollected from Irian Jaya, Seram, Sulawesi, and Timor in eastern Indonesia (Table 1, Figure 1) to bet-ter define petroleum systems in the area. A keyaspect of the petroleum system approach is to iden-tify the active source rock for each exploration play

(Magoon and Dow, 1994); however, direct oil-to-source rock correlation commonly is not possiblefor various reasons. For example, samples of ther-mally mature prospective source rock may not beavailable (as in this study), or a few discrete rocksamples may not accurately represent the verticaland horizontal compositional variations through asource rock interval that generated crude oil.

The objectives of this geochemical study were touse high-resolution geochemical methods, includingmetastable reaction monitoring-gas chromatography-mass spectrometry of biomarkers (Peters andMoldowan, 1993), to evaluate genetic relationshipsamong these oils, their source rock age and paleoen-

vironment, and their relative thermal maturity andextent of biodegradation. Most biomarkers in crudeoils are inherited from organic matter in their sourcerocks. Thus, biomarkers in crude oils allow the inter-preter to reliably predict source rock characteristics,even when rock samples are not available.

DISCUSSION

The following discussion briefly summarizes thepetroleum geology of the key areas represented bysamples in this study. The Salawati, Bintuni, andBula basins are emphasized because of significantdiscoveries and production.

Petroleum Geology of the Salawati Basin

The Salawati Basin is the most prolific oil basinin eastern Indonesia (Figure 1). About 300 millionbbl of oil have been produced from 15 fields andmore than 500 exploratory and development wellshave been drilled. Howes (1997) estimated that

about 500 million BOE will be recovered from thebasin. Our estimate is slightly higher, about 700million BOE. Walio and Kasim are the two largestfields with major production from Miocene reefallimestones of the Kais Formation and minor pro-duction from the U marker and Textularia II car-bonates above the Kais Formation (Figure 2).

Possible source rocks in the Salawati Basininclude the Klasafet and Klamogun (Miocene), Sirga(Oligocene), Kembelangan (Cretaceous– Jurassic), Tipuma (Triassic), and Aifam (Permian) formations(Phoa and Samuel, 1986; Bradshaw et al., 1997, andreferences therein) (Figure 2); however, little evi-dence supports viable Mesozoic or Permian sourcerocks (e.g., Howes and Tisnawijaya, 1995). Mostrocks of these ages in the basin are metamorphosed(Permian), missing (Jurassic), or show no generativepotential (Cretaceous claystones). The Miocene-Kais(.) (. = hypothetical) petroleum system (source-reservoir) in this basin is described as hypothetical

because no geochemical correlations between thesource and proven accumulations are available.

Petroleum Geology of the Bintuni Basin

The first field in the Bintuni Basin (Figure 1) wasnot discovered until 1990. Howes (1997) predictedultimate recoverable reserves of more than 1.5 bil-lion BOE from the basin. Based on the recent dis-covery of huge deep gas reserves in the Wiriagarfield, we estimate much higher ultimate recoveriesnear 3.5 billion BOE, including about 200 millionBOE for the shallow oil in the Wiriagar field

(Miocene Kais reservoir).Basement in the Bintuni Basin consists of meta-

morphic rocks of the Silurian or Devonian KemumFormation. Middle Carboniferous–Upper Permianshallow-marine clastic rocks of the Aifam Groupunconformably rest upon the basement. The AifamGroup consists of Aimau, Aifat, and Ainim forma-tions. The lowermost Aimau Formation containsinterbedded shallow-marine sandstones and shales. The overlying Aifat Formation is mainly UpperPermian calcareous marlstone and claystone.Conformably overlying the Aifat Formation, theUpper Permian Ainim Formation consists of fluvialdeltaic and marine claystones, sandstones, coals,and carbonaceous shales. The Triassic– Jurassic Tipuma Formation unconformably overlies theAinim Formation. The Tipuma consists of alternat-ing fluvial sandstones and shales with minor evap-orites deposited under continental and shallow-marine conditions.

Lower–Middle Jurassic Kembelangen Formationmarine deltaic shales [Inanwatan polysequence of Fraser et al. (1993)] probably are the best sourcerocks in the Bintuni Basin, but no oil-to-source rock

Peters et al. 1929



correlation has been published. Other inferred or possi-ble source rocks include the Pliocene SteenkoolFormation, upper Miocene Klasafet Formation, andPermian Ainim and Aifat formations (Collins andQureshi, 1977; Chevallier and Bordenave, 1986; Dolanand Hermany, 1988; Bradshaw et al., 1997). Little evi-dence is available to support viable Steenkool or Klasafetsource intervals. The deep Wiriagar gasprobably orig-

inated from Paleozoic, possibly Permian, source rock(Bradshaw et al., 1997, and references therein).

Petroleum Geology of the Banggai Basin,Sulawesi

Tertiary rocks in the Banggai Basin (Tomori block)along the eastern coast of Sulawesi consist of Paleogenecarbonates overlain by Miocene shelf and reefal lime-stones. The overlying Pliocene sediments contain

thick claystones that provide a good regional seal.As early as 1985, gas and oil were discovered inOligocene–Miocene reefal carbonates in the off-shore Tiaka field located about 90 km southwest of Minahaki field in Figure 1. Subsequent discoverieshave been mainly gas (e.g., Minahaki field).Possible source rocks in the Banggai Basin includelower Miocene carbonaceous shale and argil la-

ceous limestone and Eocene bituminous limestoneand shale (Kartaadiputra and Samuel, 1988).Deeper Mesozoic source rocks also may exist.

Petroleum Geology of the Bula Basin, Seram

The offshore Bula field is the only producingfield in Tertiary Bula Basin in eastern Seram (Figure1). The Bula field produces 21–29°API oil from thePleistocene Fufa Formation (100–300 m depth).


Table 1. Locations and Geochemical Data for Eastern Indonesian Oil Samples*

Depth S Pr Ph Pr

Abbrev. Field Group Location (ft) API (wt. %) nC17 nC18 Ph 13Csat 13Caro CV

Wiriagar Wiriagar (GJ-90-F-115) 1 Irian Jaya m 39 0.05 0.53 0.22 2.56 –25.42 –23.89 –0.37

Cendra Cendrawasih (91-D-055) 2A Irian Jaya m 28 0.45 1.38 1.28 1.17 –19.65 –19.56 –5.36

Cendra91 Cendrawasih 91-D-055 2A Irian Jaya m 27 0.44 1.36 1.26 1.16 –19.55 –19.48 –5.43Kasim Kasim 2A Irian Jaya m 37 0.19 1.08 0.51 2.18 –21.68 –20.91 –3.22

Kl2_8510 Klalin 2 (8510) 2A Irian Jaya 8510–8536 35 0.03 0.90 0.57 1.83 –22.57 –20.87 –0.88

Klalin Klalin 2A Irian Jaya m 46 0.07 1.03 0.51 2.22 –22.71 –21.01 –0.84

Klamono Klamono 2A Irian Jaya m 19 0.37 m m m –20.24 –19.52 –3.78

LindaA5 Linda A-5 2A Irian Jaya m 22 0.68 2.12 1.73 1.35 –21.09 –20.16 –3.05

LindaB Linda B 2A Irian Jaya m 18 0.84 m m 1.24 –20.62 –20.05 –3.99

Matoa Matoa 2A Matoa(?) m 33 0.17 0.66 0.52 1.29 –19.57 –18.96 –4.23

SouthwO Southwest O 2A Salawati Seep 54 0.03 0.67 0.43 1.84 –18.88 –18.09 –4.04

Jaya Jaya 2B Irian Jaya m 36 0.23 1.01 0.58 1.96 –21.26 –20.93 –4.33

KasimB Kasim Barat (91-D-051) 2B Irian Jaya m 32 0.22 0.97 0.53 1.90 –21.54 –20.74 –3.20

Kl2_8264 Klalin 2 (8264) 2B Irian Jaya 8264–8330 44 0.01 0.92 0.54 2.35 –21.83 –20.32 –1.53

LindaT1 Linda T-1 2B Irian Jaya m Solid 0.92 m m m –20.02 –19.92 –5.22

Minahak1 Minahaki 1 (91-B-150) 2B Sulawesi m Small Small 0.96 0.61 2.22 –21.36 m m

“Walid” Walio(?)(91-D-50) 3 Irian Jaya m 27 0.37 1.28 0.80 1.72 –22.06 –21.47 –3.50

Kolo Kolo (91-C-247) 3 Sulawesi m Solid 1.21 m m m –22.11 –21.24 –2.86Oil A 3 Sulawesi m Solid 1.25 1.00 0.93 1.13 –23.36 –22.67 –2.88

Pt.Patri Pt. Patrindo (MOG-01-20) 3 Seram Seep m 0.08 0.41 0.23 2.21 –22.07 –20.40 –1.10

Walio Walio 3 Irian Jaya m 33 0.30 1.28 0.82 1.72 –22.04 –21.42 –3.44

AGL13S5 AGL 13-S-5 (91-A-447) 4A Seram Seep 23 1.27 m m 0.77 –28.70 –28.42 –2.13

Bula Bula 4A Seram Seep 23 1.11 m m m –28.80 –28.30 –1.61

E.Nief1 East Nief 1 (90-m-207) 4A Seram 5742–5790 19 2.00 0.20 0.32 0.74 –28.68 –28.97 –3.40

KS9016 KS-90-16, SP680 4A Seram(?) Seep 24 0.94 m m 0.48 –28.56 –28.25 –2.11

Oil B 4A Seram 7000–7028 15 2.95 0.19 0.41 0.51 –28.68 –29.10 –3.69

Aliamb Aliambata 90-HS-58 4B Timor Seep 25 0.08 m m 1.58 –29.69 –28.51 0.17

*Pr = pristane, Ph = phytane; 13Csat and 13Caro = stable carbon isotope ratio (δ13C) for saturated and aromatic hydrocarbons, respectively, relative to PDBstandard (‰); CV = canonical variable (Sofer, 1984) = – 2.53δ13Csat + 2.22δ13Caro – 11.65; %C27 = 100 × C27 /(C27 + C28 + C29) 5α,14α,17α(H), 20S + 20Rand 5α,14β,17β(H), 20S + 20R regular steranes; %C30 = C30 /(C27 + C28 + C29 + C30) 5α,14α,17α(H), 20S + 20R and 5α,14β,17β(H), 20S + 20R regularsteranes; %C27d = 100 × C27 /(C27 + C28 + C29) 13β,17α(H), 20S + 20R diasteranes; %C30d = C30 /(C27 + C28 + C29 + C30) ) 13β,17α(H), 20S + 20Rdiasteranes; %20S = 100 × 5α,14α,17α(H), 20S/(ααα20S + ααα20R) C29 steranes; %ββ = 14β,17β(H), 20S + 20R/(ββ + αα 20S + 20R) C29 steranes; %Dia =100 × total diasteranes/(diasteranes + steranes); Ster and Dia = parts per million steranes and disasteranes, respectively; 24/(24 + 27) = C

2624-

nordiacholestanes 20S + 20R/(24- + 27-nordiacholestanes) (Holba et al., 1998); %1/(1 + 2 + 3) = 100 × rimuane/(rimuane + isorimuane + isopimarane)(Figure 8); Tet/(Tet + 26) = C24 tetracyclic/(C24 tetracyclic + C26 tricyclic terpanes); Ol/(Ol + H) = oleanane/(oleanane + hopane); Ro = calculated vitrinitereflectance equivalent (% Ro) based on calibration of methylphenanthrenes (Boreham et al., 1988); m = missing or unreliable. Most parameters are describedfurther in Peters and Moldowan (1993).



Estimated oil reserves from the field are about14–16 million bbl (O’Sullivan et al., 1985).

Middle Triassic–Lower Jurassic fluvial to brackishwater sandstones and shales of the Wakuku beds orKanikeh Formation are the oldest nonmetamorphosedrocks in the Bula area (Kemp and Mogg, 1992). TheWakuku beds overlie and interfinger with the deep-marine Saman-Saman Limestone. The bioclastic andoolitic Upper Triassic–Lower Jurassic ManuselaFormation was deposited in shallower water andinterfingers with both the Wakuku beds and theSaman-Saman Limestone. The Manusela Formation isunconformably overlain by Upper Jurassic–middleMiocene Nief beds. The Nief beds consist of claystonewith abundant chert nodules, marlstone, and calcare-

ous siltstone deposited initially under bathyal condi-tions but grading upward to shallow-shelf deposits.Gribi (1974) concluded that Tertiary or Triassic–

Jurassic source rocks generated oils in the BulaBasin. Later work suggested that the oils originatedfrom marine or nonmarine carbonate-evaporitesource rocks, such as Upper Triassic–Lower Jurassic Manusela Formation micritic limestone(Price et al., 1987; Livsey et al., 1992). Deep-water Triassic carbonates on Buru Island are likely sourcerocks (Fraser et al., 1993). Oil from the East Nief 1

well is produced from the Manusela Formation andprobably originated from this source. Estimated

ultimate recovery from the hypothetical Mesozoic-Manusela(.) petroleum system in Seram is less than100 million BOE (Howes and Tisnawijaya, 1995).

Petroleum Geology of the East Timor Area

The tectonic evolution of Timor is poorly under-stood, but it is generally recognized that it originatedon the Australian shelf. A major early(?) Miocene oroge-ny separates highly tectonized preorogenic flyschdeposits from later postorogenic rocks and marks thetime of complete separation from Australia.

Petroleum seeps on the island probably originatefrom source rocks in the preorogenic sequencebecause it is unlikely that the Tertiary rocks wereburied sufficiently to reach the oil window.

The oldest preorogenic rocks consist of about1500 m of Permian turbidites, limestones, andminor interbedded volcanics that crop out on east-ern Timor. The Triassic Aitutu limestone is about1000 m thick and is overlain by Jurassic marlstonethat includes shales with turbidites and interbeddedlimestone near the top. Cretaceous–Eocene rocks

Peters et al. 1931

Table 1. Continued.

% % % % % % % % % % % Ster Dia 24 (1+2+3) (1+2+3) (1+2+3) Tet OL

C27 C28 C29 C30 C27d C28d C29d C30d 20S ββ Dia (ppm) (ppm) (24+27) (%) (%) (%) Tet+26 OL+H Ro

35.7 28.1 36.2 5.5 39.9 29.6 30.5 2.7 m m 61.7 9.0 13.1 0.38 19.56 11.99 68.45 m m 0.98

32.3 32.3 35.4 2.4 34.1 29.6 36.3 2.9 48.4 62.7 16.9 1264.2 226.3 0.25 14.95 78.14 6.91 0.62 0.70 1.27

32.8 33.3 33.9 1.9 34.4 28.8 36.8 2.3 50.1 62.8 16.7 1149.9 199.0 0.26 12.16 81.10 6.74 0.63 0.70 1.2830.7 32.9 36.4 2.6 32.8 28.9 38.4 2.4 49.8 61.5 32.3 353.8 148.3 0.29 16.71 75.23 8.06 0.63 0.64 1.18

31.2 33.7 35.1 2.3 34.8 31.1 34.0 2.6 55.4 68.0 30.8 428.6 168.3 0.30 15.54 77.05 7.41 0.50 0.72 0.93

32.6 34.4 33.0 2.1 31.2 31.0 37.7 1.3 58.0 68.3 28.9 196.2 70.4 0.26 20.27 71.56 8.17 0.52 0.73 0.92

30.2 37.2 32.6 3.7 33.0 32.1 34.9 4.7 50.3 66.5 13.9 813.9 118.5 0.25 15.77 64.58 19.64 0.56 0.59 1.08

32.0 35.9 32.1 2.0 33.4 33.7 32.9 1.7 45.7 64.3 15.2 949.2 153.8 0.29 11.00 78.00 11.00 0.63 0.68 0.98

33.1 34.7 32.2 2.0 35.3 31.2 33.5 1.7 46.5 61.2 15.3 1448.5 228.6 0.25 13.28 80.21 6.51 0.64 0.67 1.00

28.8 33.2 38.0 2.1 33.4 31.9 34.7 2.3 54.0 70.4 32.6 321.7 138.6 0.27 17.77 72.35 9.88 0.54 0.58 1.10

27.4 32.9 39.8 4.7 35.6 33.0 31.4 5.5 52.1 63.7 47.7 34.4 27.6 0.40 17.62 71.36 11.02 0.54 0.60 1.35

34.1 36.3 29.6 1.9 38.1 34.8 27.1 1.8 48.9 61.1 29.8 222.4 82.3 0.29 15.90 78.95 5.15 0.61 0.60 1.07

32.5 34.4 33.1 2.0 39.8 30.1 30.1 2.1 45.8 59.6 34.3 286.4 133.1 0.25 13.50 81.23 5.27 0.64 0.66 1.40

33.2 33.4 33.4 3.3 39.0 30.5 30.5 3.5 56.1 66.8 43.0 33.8 22.7 0.32 17.74 75.51 6.75 0.48 0.59 0.91

36.3 32.0 31.7 1.9 37.5 29.3 33.2 1.7 48.6 61.6 16.6 1339.0 239.8 0.26 16.73 76.05 7.22 0.62 0.66 1.01

29.3 37.5 33.1 3.4 38.8 31.4 29.8 3.5 50.1 62.4 36.3 73.3 37.4 0.35 22.40 64.81 12.79 0.74 0.49 0.85

28.3 28.7 43.0 2.7 33.5 27.7 38.8 1.7 49.6 61.7 21.7 1035.3 255.2 0.31 20.72 70.37 8.91 0.51 0.46 1.01

28.4 31.7 39.9 2.0 36.5 27.9 35.6 1.6 51.8 63.7 36.7 914.2 479.6 0.28 17.60 66.96 15.44 0.57 0.36 0.7727.6 27.4 45.0 3.2 36.2 26.0 38.8 1.7 50.7 65.6 32.6 331.6 144.6 0.28 17.90 70.47 11.63 0.63 0.46 0.76

25.2 32.3 42.5 3.3 35.2 29.1 35.8 2.4 52.9 66.6 41.2 133.1 83.4 0.35 33.61 52.73 13.66 0.68 0.24 0.83

26.8 30.5 42.7 2.0 33.5 27.9 38.6 1.5 48.7 65.1 21.9 1125.9 284.4 0.27 19.69 73.28 7.03 0.52 0.48 1.01

29.3 29.3 41.4 3.9 29.1 27.6 43.3 4.9 53.6 65.4 15.8 367.9 59.5 0.22 35.92 10.20 53.88 0.91 0.00 0.89

29.5 28.7 41.8 3.9 29.1 29.5 41.5 5.3 49.8 62.0 18.0 536.1 102.9 0.24 43.94 6.58 49.48 0.89 0.00 0.87

27.4 30.4 42.2 4.2 31.8 32.6 35.6 6.8 52.7 68.0 15.1 362.4 56.0 0.29 36.00 13.33 50.67 0.92 0.00 0.86

28.9 26.9 44.1 4.3 28.5 28.4 43.0 3.2 50.7 63.4 17.1 549.3 98.7 0.24 36.36 7.79 55.84 0.88 0.00 0.50

27.7 27.0 45.3 4.3 31.9 25.3 42.8 4.0 42.3 58.1 7.8 510.7 35.4 0.24 35.06 11.80 53.15 0.92 0.00 0.71

30.9 24.5 44.7 5.7 32.7 22.3 45.0 4.1 54.1 65.6 45.2 590.8 436.9 0.15 41.67 21.41 36.93 0.61 0.00 0.69




F i g u r e 2 —

G e n e r a l i z e d s t r

a t i g r a p h i c c o l u m n s f o r S a l a w a t i a n

d B i n t u n i b a s i n s , e a s t e r n I n d o n e s i a .

N o v e r t i c a l s c a l e i s i n t e n d e d .

S =

s o u r c e r o c k ,

R =

r e s e r v o i r r o c k ,

C = c a p r o c k ( s e a l )

L I T H O L O G Y

F O R M A T I O N

T H I C K N E S S

P R O D

P E T R O L E U M S Y S T E M E L E M E N T S

R E C E N T

M I O C E N E

M I O C E N E

E O C E N E

E O C E N E

P A L E O C E N E

U P P E R

J U R A S S I C

L O W E R

J U R A S S I C

C A R B O N I -

F E R O U S

M I D D L E

T R I A S S I C

P E R M I A N

C R E T A C E O U S

S T E E N K O O L

K L A S A F E T

N E W G

U I N E A

L I M E S T O N E

F A U M A I

W A R I P I

J A S S

K E M B E L A N G A N

T I P U M A

A I N I M

A I F A T

A I M A U

R a p i d b a s i n f i l l ,

v a r i a b l e t h i c k n e s s

S h o a l a n d p l a t f o r m l i

m e s t o n e

N e a r s h o r e m a r i n e

a n d

s a b k h a d e p o s i t

s

D e e p m a r i n e

b a s i n f i l l

S y n r i f t c o n d e n s

e d

s e q u e n c e s , v a r i a

b l e

d i s t r i b u t i o n

C o n t i n e n t a l r e d b e d s ,

v a r i a b l e d i s t r i b u

t i o n ,

C a r b o n a t e - p r o n e t

o w e s t

W i d e l y d i s t r i b u t e d

p a r a l i c

c l a s t i c s , h i g h l a t i t u d e

f l o r a t o w a r d b

a s e

C R S S R R R S R

B I N T U N I B A S I N

A G E

S A

L A W A T I B A S I N

P R O D

A G E

L I T H O

S T R A T I G R A P H Y

P E T R O L E U M S Y S T E M E L E M E N T S

R S

+ + + + +

+ + + +

+ + + + +

+

+

A I F A M T

I P U M A

K E M B E

L A N G A N

S E L E

K L

A S A M A N

K L A S A F E T

K A I S

F M

S I R G A

F M

F A U M A

I M S K I N

F M

T h i c k r a p i d b a s i n f i l l

P i n n a c l e a n d s h

o a l

r e e f s o n b r o a d p l a

t f o r m

T S T S A N D

P r e d o m i n a n t l y p l a t f o r m ,

r a r e r e e f s

O u t e r n e r i t i c - b a t h y

a l

b a s i n f i l l

J u r a s s i c - s y n r i f t / p

o s t r i f t

T r i a s s i c - c o n t i n e n t a l

P e r m i a n - m a s s

i v e

d o l o m i t e s a n d p a

r a l i c

c l a s t i c s

S R R

C C R

K LA M O

G U N

S A L A W A T I

G R A N I T E

K E M U M

Q

P L E I S T O C E N E

L A T E

E A R L Y

L A T E

M I D D L E

E A R L Y

E A R L Y

L A T E

T E R T I A R Y

P L I O C E N E M I O C E N E E O C E N E P A L E O C E N E

P R E - T E R T I A R Y

P E R M I A N

T R I A S S I C

S I L U R O - D E V O N I A N

L A T E C R E T A C E O U S

I N T R U S I O N

T E X T . I I L S T

O L I G O C E N E

S

N

S

M E T A - S E D I M E N T S



consist of radiolarian claystone, calcilutite, varie-gated chert, and limestone. Postorogenic subsi-dence resulted in deposition of up to 4000 m of clastics in basins within the Timor area. Tertiaryrocks in these basins consist mainly of deep-watercarbonates overlain by up to 2000 m of Pliocene–Pleistocene clastics.

Crostella and Powell (1975) concluded that surface oilseeps in east Timor originated from Jurassic and Triassicsource rocks. A hypothetical Mesozoic– Tertiary(.)petroleum system is inferred for Timor Island (Howesand Tisnawijaya, 1995; ten Haven and Schiefelbein,1995; Bradshaw et al., 1997). Although more than twodozen wells have been drilled, no significant petroleumaccumulations have been discovered.

Geochemistry of the Oils

Chemometric analysis of source-related biomark-er and stable carbon isotopic data was based on 13source-related parameters for the oils as describedin the Appendix, and resulted in four geneticgroups (Figure 3, Table 1):

Probable Lower–Middle Jurassic OilsGroup 1 consists of oil from the shallow

Miocene Kais reservoir in the Wiriagar field in the

Bintuni Basin of Irian Jaya (Figure 3). The low-sulfur(0.05 wt. %), light (39° API) (Table 1) Wiriagar oilis nonbiodegraded based on unaltered n-paraffins,but shows evidence of evaporative loss of lightends and extensive migration fractionation asmight occur during repeated retrograde conden-sations (Figure 4). The oil contains very lowbiomarkers (e.g., 9 vs. 34–1449 ppm steranesfor the other samples), which complicates theinterpretation.

The high pristane/phytane ratio (Pr/Ph = 2.56)and plot locations in Figures 5 and 6 indicate thatthe source rock for the shallow Wiriagar oil con-tains mixed terrigenous and marine type II/IIIorganic matter deposited under oxic conditions. The stable carbon isotope, sterane, and tricyclicditerpane compositions for this oil are distinc-tive (Figures 6–8), suggesting that it was derived

from a different source rock than the other oilsamples.Although steranes and diasteranes are low, the

high diasterane ratio [diasterane/(diasterane + regu-lar steranes) = 62%] suggests that the shallowWiriagar oil originated from a clay-rich clastic rock.Clay-rich source rocks generate low-sulfur oils thatare enriched in diasteranes because clays arerequired to catalyze the transformation of steroidsto diasteranes, and metals in the clays compete forsulfur that might otherwise be incorporated into

Peters et al. 1933

Figure 3—Dendrogram showsgenetic relationships amongoils based on chemometricanalysis of selectedsource-related geochemical data(Table 1). Cluster distance is ameasure of genetic similarity

indicated by the horizontaldistance from any two sampleson the left to their branch pointon the right.

Wiriagar

Southw O

Matoa

Linda B

Linda A5

Klamono

Klalin 2_8510

Klalin

Kasim

Cendra91

Cendrawasih

Minahaki 1

Jaya

Linda T1

Klalin 2_8264

Kasim B

Walio

“Walid”

Kolo

Oil A

Pt. Patrindo

Oil B

Bula

AGL13S5

KS9016

E. Neif 1

Aliambata

1

2A

3

4A

2B

4B



the organic matter and generated oil (Peters andMoldowan, 1993). Conversely, clay-poor carbonatesource rocks commonly generate high-sulfur oilswith low diasteranes.

The shallow Wiriagar oil lacks oleanane, consis-

tent with a Jurassic or older marine source rock,and contains high 24-n-propylcholestanes (C30steranes, Figure 9). Oleanane is a biomarkerderived from angiosperms (flowering plants) thatoriginated in the Cretaceous but did not dominatethe land until the Tertiary (Peters and Moldowan,1993; Moldowan et al., 1994). The C30 24-n-propylcholestanes are diagnostic of marine sourcerock depositional environments (Moldowan et al.,1985; Peters et al., 1986). The isotopic composi-tions of the saturated and aromatic hydrocarbons

for this oil (Figure 6) are consistent with aMesozoic source rock but are not typical of Tertiaryor Paleozoic oils (Chung et al., 1992). On this basis,a Permian source for the shallow Wiriagar oil isunlikely. The high C26 24-nordiacholestane ratio for

the shallow Wiriagar oil (0.38, Table 1) would nor-mally indicate a Cretaceous or younger source rockage (Holba et al., 1998); however, this high valuefor shallow Wiriagar oil is not reliable because of low biomarker concentrations.

The East Onin 1 well from the Babo block in theBintuni Basin (Harrington, 1996) (Figure 1) is locat-ed near the Wiriagar field. This well contains about350 m of highly mature Lower–Middle JurassicKembelangan source rock with high residual totalorganic carbon (total organic carbon or TOC ≈


GROUP 1Wiriagar

GROUP 2ASouthwest Obi

GROUP 2B

Jaya

GROUP 3

Walio

GROUP 4AOil B

Pristane

Phytane

Phytane

Oleanane

Hopane

HopaneNorhopane

Oleanane

Hopane

Gas Chromatograms Terpane Mass Chromatograms

m/z 191

TricyclicTerpanes

OleananeHopane

Figure 4—Representative gaschromatograms (left) andterpane mass chromatograms(m/z 191) (right) for the oilsamples.



1.5–2.5 wt. %). Rock-Eval pyrolysis hydrogen indicesin this interval are low (∼90 mg HC/g TOC) but wereprobably higher (∼200 mg HC/g TOC) prior to ther-mal maturation. This shale-rich interval probablygenerated large amounts of wet gas and some oil and

could be the source for the shallow Wiriagar oil.High methylphenanthrene and diasterane ratioscombined with low biomarker concentrations sug-gest a maturity past peak oil window (∼1.0%Ro) forthe shallow Wiriagar oil (Table 1), which is similar to

Peters et al. 1935

100

E. Nief1 Oil B

0.1

1

10

0.1 1 10

Phytane/n C18

P r i s t a n e / n C 1 7

T e r r i g

e n o u s

T y p e I I

I

M i x e d

T y p e I I / I I I

M a r i n e

A l g a l T

y p e I IO

x i d i z i n g

R e d u c i n g

Group1234

Figure 5—Plot of pristane/n-C17 vs.phytane/n-C18 fromwhole-oil chromatogramscan be used to inferoxicity and organicmatter type in the

source rock depositionalenvironment. Increasingthermal maturation andbiodegradation displacepoints toward the lowerleft and upper right,respectively.

Figure 6—Stable carbonisotope ratios (‰relativeto PDB standard) forsaturated vs. aromatichydrocarbons differbetween oil groups andcan be used to infer therelative amounts of terrigenous vs. marineorganic matter in theirsource rocks. The dottedline, showing bestseparation, is based ona statistical analysis of hundreds of knownmarine and terrigenouscrude oils (Sofer, 1984).

Aliambata

Wiriagar

-31

-29

-27

-25

-23

-21

-19

-17

-31 -29 -27 -25 -23 -21 -19 -1713CSaturates

1 3 C A r o m a t i c s

Marine

Terrigenous S o f e r (

1 9 8 4 )

Group1

234

δ

δ



that in the Kembelangan interval from the East Onin 1well (Tmax ≈ 460–470°C, Ro ≈ 1.0–1.3%).

The Bintuni Basin is likely to contain at least oneadditional oil type (Chevallier and Bordenave, 1986).For example, ten Haven and Schiefelbein (1995)found abundant oleanane in oils from Jagiro, Mogoi,and Wasian fields, suggesting a Tertiary source rock,although these oils were previously considered tooriginate from a Permian source (Dolan and Hermany,1988). These oils were not available for our study.

Tertiary Marine Marlstone OilsGroups 2 and 3 consist of geochemically similar

oils that contain oleanane and originated from marinemarlstone source rocks of Tertiary age. Group 2 oilsare mostly from the Salawati Basin in Irian Jaya (Figure3). Subgroup 2A consists of oils from Matoa, Linda B,Linda A5, Klamono, Klalin 2 (8264 ft; 2520 m depth),Klalin, Kasim, Cendrawasih, Cendrawasih 91 D-055(Irian Jaya), and Southwest O (Salawati Island nearIrian Jaya). Subgroup 2B consists of oils from Jaya,


70% C27

70% C28 70% C29

Group1234

X = H, CH3, C2H5

XSteranes

Figure 7—Ternary diagram of C27,C28, and C29 sterane compositionfor oils based on high-resolutionbiomarker analysis (metastablereaction monitoring-gaschromatography-massspectrometry). Chemical

structures are shown at left.The corners of the trianglerepresent the relative percentageof the corresponding steranehomolog.

Figure 8—Ternary diagram of relative percentages of threetricyclic diterpanes in oils(rimuane, isorimuane, andisopimarane structures at left)based on high-resolutionbiomarker analysis (metastablereaction monitoring-gaschromatography-massspectrometry). The

stereochemistries of therimuane isomers are notknown. The corners of thetriangle represent 100% of the corresponding tricyclicditerpane.

Group1234

100% 2/(1+2+3) 100% 3/(1+2+3)

100% 1/(1+2+3)

Aliambata

Diterpanes1 = Rimuane2 = Isorimuane?

3 = Isopimarane



Linda T1, Klalin 2 (8510 ft; 2595 m depth), and KasimBarat (Irian Jaya) and Minahaki 1 (Sulawesi).

Group 2 and 3 samples show high oleanane ratiosand C30 24-n-propylcholestanes that are diagnostic of a Tertiary marine source rock (Figure 9). Oleanane/(oleanane + hopane) ratios over 0.20 in oils are diag-nostic of Tertiary source rock (Moldowan et al., 1994).Another age-related biomarker ratio provides indepen-dent support for the interpretation of Tertiary sourcerock. All group 2 and 3 oils show high 24-nordia-

cholestane ratios (0.25–0.40 and 0.27–0.35, respective-ly, Table 1), where ratios greater than 0.25 are diagnosticof oils from Cretaceous or Tertiary source rocks (Holbaet al., 1998); furthermore, the saturated and aromatichydrocarbons for group 2 and 3 oils are enriched in 13C(Figure 6), typical of Oligocene–Miocene rather thanMesozoic oils (Chung et al., 1992).

Group 2 and 3 oils show no evidence for signifi-cant contamination by nonindigenous oleanane.Such contamination is rare because biomarkers inmigrating oils commonly overwhelm the compara-tively small amounts of contaminants in organic-lean carrier beds and reservoir rocks (Peters and

Moldowan, 1993). If oleanane were a contaminantsolubilized by migration of mature oil through lessmature carrier beds, one would expect mixedmaturity signals depending on the origin of thecompounds used for each maturity parameter;however, the 18α/18β oleanane stereoisomer ratiosfor these oils are consistent with independentmaturity parameters from other biomarkers in thesamples; furthermore, as discussed in previousparagraphs, all of the oils that show high oleananeratios also show high 24-nordiacholestane and

13C-rich isotope ratios, consistent with a Tertiaryage for their source rocks.

The Klamono (0.37 wt. %sulfur, 19°API, Table 1)and Linda T1 (0.92 wt. %sulfur, solid) oils are moder-ately biodegraded based on the absence of n-paraffinsand isoprenoids but have unaltered steranes (level 5)(Peters and Moldowan, 1993). Linda B oil (0.84 wt. %sulfur, 18° API) is mildly biodegraded based on thelack of n-paraffins but unaltered isoprenoids (level 3).Oils from Linda A5 (0.68 wt. % sulfur, 22° API) and

Cendrawasih and Cendrawasih 91 D-055 (0.44–0.45wt. %sulfur, 27–28°API) show evidence of very mildbiodegradation of n-paraffins (level 1).

Nonbiodegraded group 2 oils show Pr/Ph ratios inthe range from 1.29 to 2.35, low sulfur (0.01–0.23wt. %, Table 1), and isoprenoid to n-paraffin ratiosthat indicate an origin from mixed type II/III organicmatter deposited under suboxic conditions (Figure5). The stable carbon isotope compositions of satu-rated and aromatic hydrocarbons for these oils(Figure 6) and the resulting calculated canonical vari-ables (CV, see Table 1) indicate mostly marine organ-ic matter in their source rocks.

Most group 2 and 3 oils show moderate diaster-ane ratios (20–40%, Table 1), suggesting a calcare-ous claystone or marlstone source rock with claycontent between pure carbonate and clay-rich silici-clastic. We use the term“marlstone” to describe thelithology of the source rock for most oils in thesetwo groups. Some group 2 oils, such as the Linda A-5, B, and T-1 samples, show low diasterane ratios(<20%, Table 1), suggesting carbonate source rock. The Southwest O oil shows a high diasterane ratio(47.7%), low sulfur (0.03 wt. %), and high API gravity

Peters et al. 1937

Figure 9—Plot of oleananevs. C30sterane(24-n-propylcholestane)ratios separates oil groups.Oleanane ratios for oilsgreater than 0.20 indicateTertiary source rocks

(groups 2 and 3), whereasthe absence of oleanane isconsistent with a Jurassic orolder source (group 4). C30

24-n-propylcholestanesare diagnostic of marinesource rock depositionalconditions. The C30steraneratio generally increaseswith marine vs. terrigenousorganic-matter input to thesource rock. Wiriagar oilis problematic becausebiomarkers are low.This oil lacks oleanane but

shows high C30steranes.

Group1234

AliambataWiriagar

Ol/(Ol + H)

% C 3 0 S t e r a n e s

0

2

3

4

5

0.2 0.4 0.6

Tertiary Oils

Triassic-Jurassic

Oils



(54°) because it is very mature based on themethylphenanthrene ratio (1.35%Roequivalent, Table 1).

Group 3 consists of oils from Walio, “Walid”(I rian Jaya), Kolo, Oi l A (Sulawesi), and PointPatrindo (Seram). These oils are geochemically sim-ilar to group 2 oils (Figures 5–8), but show loweroleanane ratios (Figure 9), which still exceed 0.20and thus are diagnostic of Tertiary source rocks.

The Kolo oil is moderately biodegraded based onabsence of n-paraffins and isoprenoids but unalteredsteranes (level 5) (Peters and Moldowan, 1993). Thissample is a solid that contains high sulfur (1.21 wt. %)due to the biodegradation. Oil A is also a solid with highsulfur (1.25 wt. %), which shows evidence of very mildbiodegradation of n-paraffins (level 1–2). Nonbio-degraded group 3 oils show low sulfur (0.08–0.37 wt. %sulfur) and moderate API gravity (27–33°API), similar tothe nonbiodegraded group 2 oils.

Triassic– Jurassic OilsGroup 4 contains two genetic subgroups; bothsubgroups are characterized by lack of oleanane.Subgroup 4A consists of oils from the Bula Basin ineastern Seram, including Bula, AGL13S5, KS-90-16,East Nief 1, and Oil B. Subgroup 4B consists of theAliambata seep oil from eastern Timor Island. AMesozoic source rock was previously inferred foroils from Timor and Seram (Price et al., 1987; tenHaven and Schiefelbein, 1995). Although mildlybiodegraded (level 1) (Peters and Moldowan,1993), the Pr/Ph ratio and biomarker characteris-tics of the Aliambata oil are similar to publisheddata for crude oils derived from the Upper Jurassic

Dingo Formation in the Barrow subbasin of Western Australia (Volkman et al., 1983).

The Bula seep oil (1.11 wt. % sulfur, 23° API) ismoderately biodegraded based on absence of n-paraf-fins and isoprenoids but unaltered steranes (level 5)(Peters and Moldowan, 1993). Oil seep samplesAGL13S5, KS9016 (0.44–1.27 wt. % sulfur, 24–25°API) and Aliambata (0.08 wt. % sulfur, 25° API) aremildly biodegraded based on lack of n-paraffins butunaltered isoprenoids (level 2–3). Oil B shows highsulfur (2.95 wt. %) and low API gravity (15° API)because of low thermal maturity (Figure 10).

The subgroup 4A oils are distinguished by very lowPr/Ph ratios (0.48–0.77), high sulfur (0.94–2.95 wt. %),and low API gravity (15–24°API) (Table 1). The Pr/Phratio could not be measured for the biodegraded Bulaseep oil. Low Pr/Ph ratios (<1) and high sulfur (>0.5wt. %) for oils are characteristic of highly reducingor anoxic source rock depositional conditions. TheEast Nief 1 oil and Oil B show Pr/n-C17 and Ph/n-C18ratios consistent with an origin from marine type IIsource rock deposited under highly reducing to anox-ic conditions (Figure 5). The remaining seep oils lackreliablen-C17 andn-C18 peaks due to biodegradation.

Biomarker and other parameters for the subgroup4A oils are consistent with an anoxic marine carbon-ate source rock. For example, these oils show lowdiasterane ratios (8–18%, Table 1), low tricyclic ter-panes, high norhopane/hopane ratios (e.g., Oil B inFigure 4), high 30-norhopanes, and high sulfur(0.94–2.95 wt. %), consistent with a clay-poor anoxiccarbonate source rock (Subroto et al., 1992; Peters andMoldowan, 1993).

The high Pr/Ph ratio (1.58) and low sulfur (0.08 wt. %)for the Aliambata oil suggest a suboxic source rock depo-sitional environment. The high diasterane ratio for theAliambata oil (45%, Table 1) indicates a clay-rich sourcerock, which is supported by the low sulfur content.

Stable carbon isotopic compositions for the saturat-ed and aromatic hydrocarbon fractions of the group 4oils are depleted in 13C compared to the other oils inthe study and are typical of Mesozoic rather thanOligocene–Miocene oils (Chung et al., 1992) (Figure6). The plot location for these oils in Figure 6 and their

calculated canonical variables (CV, see Table 1) indi-cate mainly marine source rock organic matter. TheAliambata oil shows a higher CV than the other group4 oils (0.17 vs. –1.6 to –3.7), suggesting that its sourcerock received more terrigenous organic matter.

The group 4 oils are enriched in C29 steranescompared to most other samples in the study (Figure7), suggesting that their source rock receivedgreater higher plant input; however, the composi-tion of the higher plants that contributed to thegroup 4 oils was distinct from that of the othergroups. For example, the group 4 oils show differ-ent distributions of tricyclic diterpanes than theother groups (Figure 8) and lack oleanane (Figures

4, 9). Lack of oleanane indicates an absence of flowering higher plants and suggests that thesource rock is Jurassic or older. Except for the E.Nief 1 oil (0.29), most group 4 oils show low C2624-nordiacholestane ratios (0.15–0.24, Table 1),consistent with a Jurassic or older age (Holba etal., 1998).

The group 4 oi ls contain more C30 24-n-propylcholestanesthan most oils in the studyexcept Wiriagar oil, suggesting strongly marinedepositional conditions for the source rock (Figure9). The Aliambata oil shows a higher C30 24-n-propylcholestane ratio than the other group 4 oils,consistent with other data that indicate Aliambataoil is different from the other group 4 oils.

Table 2 summarizes key geochemical parametersfor each oil group and the inferred characteristicsof their source rocks.

CONCLUSIONS

Only 7 of the 27 oil samples in this study origi-nated from Triassic– Jurassic source rocks. These




seven oils, designated Wiriagar, Bula, Oil B, EastNief 1, AGL, KS9016, and Aliambata, occur in thesouthern portion of the study area on Seram (fiveoils), Timor (one oil), and Irian Jaya (one oil). Low-sulfur, high API gravity Wiriagar oil from Irian Jayais nonbiodegraded, highly mature, and geochemi-cally distinct from the other oils. The geochemicalcomposition of the oil suggests that it originatedfrom a pre-Cretaceous marine clay-rich clasticsource rock that contained mixed type II/III organ-ic matter, probably Lower–Middle JurassicKembelangan Formation [Inanwatan polysequenceof Fraser et al. (1993)].

Samples designated Bula, Oil B, East Nief 1,AGL, and KS9016 show high sulfur and low APIgravity and originated from type II organic matterin an anoxic marine carbonate source rock. Low-sulfur Aliambata oil originated from a marine clas-tic source rock that contained mixed type II/IIIorganic matter deposited under more oxic condi-tions. The source rock for the Aliambata oil was amore terrigenous-influenced, shaly equivalent of

the marine carbonate source rock. The Aliambataoil is geochemically similar to Upper JurassicDingo Claystone oils from Western Australia. Thesource rocks for these six oils are probably synrift-postrift shales and carbonates like those in theLower–Middle Jurassic Kembelangan Formation inthe Bintuni Basin or Triassic carbonates on BuruIsland.

The remaining 20 oils in the study originatedfrom Tertiary source rocks based on high oleananeand C26 24-nordiacholestane ratios; furthermore,

the 13C-enriched stable carbon isotope composi-tions of these oils typify Oligocene–Miocene oils. These oils are found in the northern portion of thestudy area near Irian Jaya (16 oils), Sulawesi (threeoils), and Seram (one oils). Oils from Matoa, LindaB, Linda A5, Linda T1, Klamono, Klalin, Klalin 2(8264 ft; 2520 m depth), Klalin 2 (8510 ft; 2595 mdepth), Cendrawasih, Cendrawasih 91 D-055, Jaya,Kasim, Kasim Barat, Southwest O (Irian Jaya), and

Minahaki 1 (Sulawesi) originated from a marinemarlstone source rock. This source rock containedmixed type II/III organic matter deposited undersuboxic conditions. Oils from Walio, “Walid” (Irian Jaya), Kolo, Oil A (Sulawesi), and Point Patrindo(Seram) are geochemically similar to these oils butshow lower oleanane ratios. These oils probablyoriginated from upper Miocene Klasafet Formationsource rocks.

We estimated the ultimate volumes of recoveredpetroleum contributed by each of the oil groups ineastern Indonesia. Estimated ultimate recoverablereserves in the study area are about 4.3 billion BOE

(bbl of oil equivalent), assuming that the Bintuni,Salawati, Bula, and Banggai basins will produceabout 3.5 billion, 700 million, 100 million, and 15million BOE, respectively. The shallow and deepWiriagar accumulations account for about 0.2and 3.3 billion BOE, respectively; therefore, theinferred Lower–Middle Jurassic Kembelangansource for shallow Wiriagar oil (group 1) accountsfor about 5%, and the deep Wiriagar accumulation,presumed to originate from Paleozoic source rock,accounts for about 77% of the estimated ultimate

Peters et al. 1939

KS9016

AGL13S5Aliambata

Bula

Cendra

Cendra91

E. Nief 1

Jaya

KasimB

Kasim

Klalin

KI2_8264

KI2_8510

Klamono

Kolo, SouthwO

LindaA5

LindaB

LindaT1

Matoa

Minahaki1

Oil B

Pt.Patri

Oil A

“Walid”

Walio

50

55

60

65

70

75

40 45 50 55 60

%C29αα20S

% C 2 9

β β 2

0 R

Group

1

2

3

4

Figure 10—Oil samplesshow a range of thermalmaturity based on twomaturity-related biomarkerparameters [%20S/(20S +20R) and %ββ/(ββ +αα),Table 1]. Shaded areas

represent end-point valueswhere further maturationdoes not significantlyincrease ratios. Samplesin the shaded area arenear or past peak oilgeneration. Plot locationfor Wiriagar oil isproblematic becauseof low steranes.High methylphenanthreneand diasterane ratioscombined with lowbiomarker concentrationssuggest a maturity near

peak oil window(∼1.0% Ro) for theWiriagar oil.



recovery in the study area. The Tertiary oils from theSalawati and Banggai basins (groups 2 and 3) and the Triassic– Jurassic oils from Seram and Timor (group4) account for about 16 and 2%, respectively, of esti-mated ultimate recovery in the study area.

APPENDIX: METHODS

Bulk Properties

Crude oil API gravity was determined at 15.6°C (60°F) bypycnometry. Sulfur was measured by ASTM standard test methodD-5453 using an Antek 771 Pyroreactor™ coupled with an Antek714™ ultraviolet sulfur detector. Samples were introduced intothe pyroreactor using an Antek 735™ syringe drive to ensurereproducibility. The method accurately determines sulfur contentsranging from 1 ppm to 8 wt. %in liquid hydrocarbons with boilingtemperatures ranging from 25 to 400°C.

Liquid Chromatography

Hexane was added to the whole oil, and precipitated asphal-tenes were removed using a cartridge filter. Saturated and aromat-ic hydrocarbon fractions were separated from the remaining oilby high-performance liquid chromatography (HPLC), using refrac-

tive index and ultraviolet detectors as described in Peters andMoldowan (1993).

Gas Chromatography

Gas chromatograms (GC) of whole oils were run using aHewlett Packard 5890™ gas chromatograph equipped with aflame ionization detector and a 30 m× 0.32 mm i.d. J&W DB-1HT™ column (0.1 µm film thickness). The GC was temperatureprogrammed from–15 to 340°C at 25°C/min and held at 340°Cfor 10 min using helium as the carrier gas.

Gas Chromatography-Mass Spectrometry

Metastable reaction monitoring-gas chromatography-massspectrometry (MRM-GCMS) and gas chromatography-mass spec-trometry (GCMS) were used to analyze steranes and terpanes inthe C15+saturated hydrocarbon fractions of the crude oils. Semi-quantitative GCMS analysis of terpanes was achieved using aHewlett Packard 5890 Series II™ gas chromatograph coupledeither to a Hewlett Packard 5970™ or Hewlett Packard 5972™mass spectrometer. Oils were spiked with 500 µL of a hexane solu-tion containing 0.01 g/L of 5β(H)-cholane and 500 µL of a 0.1 g/L hexane solution of anthracene before the high-performance liq-

uid chromatography (HPLC) group-type separation. Because nei-ther compound is found in oils, the addition of 5 µg of each servesas an internal standard. Cholane behaves in the mass spectrometerin the same manner as steranes and other saturated polycyclicbiomarkers. Its presence in an oil allows compensation for sampleloss, biomarker fractionation, and variations in injection tech-nique, gas chromatographic performance, and mass spectrometricsensitivity. Response factors for individual biomarkers relative tospecific ions and the cholane internal standard vary with instru-ment conditions and thus are difficult to determine; therefore, theterpane quantification assumes that all compounds produce aresponse of unity. Using this approach, the quantities of terpaneswere calculated as relative rather than absolute values.

High-resolution quantitative MRM-GCMS analysis of steraneswas achieved by analysis of aliquots of the spiked saturated hydro-carbon fraction described using a VG 7070E-HF™ double focusingmagnetic sector instrument (Biomarker Technology, Inc.).

Response factors for individual compounds were used to quantifyabsolute amounts of steranes and diasteranes in the samples.Detailed procedures and compound identifications for steranesand terpanes are in Peters and Moldowan (1993).

Stable Carbon Isotopes

Stable carbon isotope ratios (δ13C) were measured on C15+sat-urated and aromatic hydrocarbon fractions using a Finnigan DeltaE™ isotope ratio mass spectrometer and methods described bySchoell et al. (1983). Data are reported in parts per thousand (‰)


Table 2. Summary of Measured Oil Properties and Inferred Source Rock Characteristics

Group 1* Group 2** Group 3† Group 4A†† Group 4B§

Measured Oil Properties§§

Pr/Ph 2.6 1.2–2.4 1.1–2.2 0.5–0.8 1.6Wt. %Sulfur 0.1 0–0.2 0–0.4 0.9–3.0 0.1

°API 39 32–37 27–33 15–24 25δ13C (‰) –25.4 –18.9 to –22.7 –22.1 to –23.4 –28.6 to –28.8 –29.7OL(OL + H) 0 0.49–0.73 0.24–0.48 0 024/(24 + 27) 0.38 0.25–0.39 0.27–0.35 0.22–0.29 0.15

Inferred Source-Rock CharacteristicsAge Lower–Middle Jurassic Miocene Miocene Triassic– Jurassic Triassic– JurassicLithology Marine clay-rich clastic Marine marlstone Marine marlstone Marine carbonate Marine shaleRedox Oxic Suboxic Suboxic Anoxic SuboxicKerogen Type II/III Type II/III Type II/III Type II Type II/III

*Wiriagar oil.**Matoa, Linda (3), Klamono, Klalin (3), Kasim, Kasim Barat, Cendrawasih (2), Jaya, Minahaki, Southwest O oils.†Walio, “Walid,” Oil A, Kolo, Point Patrindo oils.††KS-90-16, AGL 13S5, Bula, E. Nief, Oil B oils.§Aliambata oil.§§Pr/Ph, wt.% sulfur, and API gravity values are for nonbiodegraded or mildly biodegraded samples. Ol/(Ol + H) = oleanane/(oleanane+hopane); 24/(24 + 27) =

C26 (24-nordiacholestanes, 20S + 20R)/(24 – + 27-nordiacholestanes (Holba et al., 1998).



relative to the PDB standard. The NBS-22 oil standard was used forcalibrations and measures–29.75 ±0.05‰relative to PDB.

Multivariate Statistics

Statistical analysis of multivariate geochemical data was com-pleted using a commercial chemometrics program (PirouetteVersion 2.03, Infometrix Inc.). Thirteen source-related geochemi-cal parameters were used in the analysis, including δ13Csaturates,δ13Caromatics, %C27 to %C29 steranes, %C27 to %C29 diasteranes,%1/(1 to 3) to %3/(1 to 3) tricyclic diterpanes, %C24tetracyclic/(C24tetracyclic + C26tricyclic) terpanes, and oleanane/(oleanane+ hopane) ratios (Table 1). Exploratory data analysis, includingcomputation and graphical display of the patterns of associa-tion in the data set, was completed using hierarchical clusteranalysis (autoscale preprocessing, Euclidean metric distance,incremental li nkage) and principal component analysis(autoscale preprocessing).

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Peters et al. 1941



Ken E. Peters

Ken Peters is an associate geo-chemical advisor at Mobil Tech-

nology Company with 21 years of experience in worldwide explo-ration and development. He servesas associate editor for the AAPGBulletin and Organic Geochemistryand was chairman of the prestigiousGordon Conference on OrganicGeochemistry in 1998. He and J. M.Moldowan are co-authors of TheBiomarker Guide. Peters has authored or co-authoredover 80 articles on petroleum geochemistry.

Tom H. Fraser

Tom Fraser is a geoconsultant

with Unocal in Jakarta, Indonesia.He has more than 12 years of expe-rience in southeast Asia, especiallyin eastern Indonesia for Mobil ,Conoco, and Maxus. His specialinterests include graphical petro-leum system presentations throughhis company Resource System Diag-nostics. Tom gained his bachelor’sdegree in geology from QMC, Lon-don University in 1969. He has worked in Europe, Egypt,Abu Dhabi, the United States, Canada, Colombia,Indonesia, Bangladesh, Burma, Vietnam, and South Korea.

Welly Amris

Welly is currently working as asenior staff geologist in theExploration (Geoscience) Depart-ment of Mobil Oil Indonesia, Inc.

Jakarta. Before he joined Mobil in1985 as a production geologist, hepreviously had worked with MaxusEnergy for four years in Jakarta. Hereceived his B.Sc. degree in geologyfrom Bandung Institute of Technology(ITB) in 1981. He is a member of the AAPG and an active member of the IndonesianPetroleum Association (IPA), as well as the IndonesianAssociation of Geologists (IAGI).

Budi Rustanto

Budy Rustanto received a B.S.degree in geology at the Pemban-

gunan National University Yogaya-karta (1986). He is currently work-ing in the Regional EvaluationExploration section for the StateOil and Gas Mining Company(PERTAMINA), Foreign ContractorManagement Body (BPPKA) Jakarta.Budi is a member of the IndonesianAssociation of Geologists (IAGI).

Eddy Hermanto

Eddy received a B.S. degree ingeology at the Pembangunan Nation-al University Yogayakarta (1987). He

is currently working in the RegionalEvaluation Exploration section forthe State Oil and Gas MiningCompany (PERTAMINA), ForeignContractor Management Body(BPPKA) Jakarta. Eddy is a juniormember of the AAPG, IndonesianAssociation of Geologists (IAGI),and Indonesian Petroleum Association (IPA).


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Oil Geochemistry of Eastern Indonesia (Peters Et Al., 1999)

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