Geochemistry of Crude Oils from Eastern Indonesia1 Ken E. Peters,2 Tom H. Fraser,3 Welly lly Amri Amris,4 Budi Rustanto,5 and Eddy Hermanto5
ABSTRACT HighHi gh-res resol olutio ution n geochemistr eochemistry y shows geneti enetic c relationships among 27 crude oils from eastern Indonesia and suggests the ages and paleoenvironments of their source rocks. Oils inferred to originate nate from fro m Terti Terti ar y and and Trias Tr iassic– sic–JJ urassic urassic source rocks in the study occur north and south of 2°S latitude, respectively. Twenty oils mainly from Irian Ja J aya and and Sulawesi ori or i ginated from f rom Terti Ter ti ar y marine marlstone source rocks that contained type type II/ II / III kerogen kerogen depos deposited ited under under suboxic suboxic conditions, probably the upper Miocene Klasafet Formation. Thes These low-s low-sulfur ulfur oils oil s show show high high oleana oleanane ne,, C26 24-nordiacholestane, and pristane/phytane ratios, and 13C-rich carbon isotope compositions. High oleanane and 24-nordiacholestane ratios are diagnostic of Tertiary oils and source rocks. These oils account for about 16% of the estimated ultimate recoverable reserves in eastern Indonesia. Five oils from Seram originated from Triassic– Juras Jurassic ma marine carbo carbona nate te source ource rock rock tha thatt concontained type II kerogen deposited under anoxic conditions. diti ons. Thes These e highhi gh-su sulf lfur ur oils oils la l ack olea oleana nane ne and and genera enerall lly y show low l ow C26 24-nordiacholestane and pristane/phytane ratios. Low-sulfur Aliambata seep oil from Timor originated from type II/III kerogen in a more oxic, terrigenous-influenced marine clastic equivalent of this carbonate source rock. These six oils account for only about 2%of the estimated ultimate recovery in the area. Low-sulfur Low-sulfur shallow ll ow oil from Miocene Miocene Kais reserreservoirs in the Wiria Wiriagar field field in in Iri Iria an Ja Jayalacksol lacks olea eanane, nane, ©Copyright 1999. The Ame rican Association of Petroleum Geologists. All rights reserved. 1Manuscript received June 16, 1998; revised manuscript received March 25, 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.COM yJAKLNM1.JAK.MOBIL.COM 5Pertamina, Jakarta Indonesia. We gratefully acknowledge Budiono and Mobil Oil Indonesia for permission to release this paper and thank Ron Noble, Wally Dow, Roy Enrico, Jim Stinnett, and Asep Sulaeman for peer reviews of the draft. John Zumberge, Brad Huizinga, and Lyle Henage provided useful discussions of samples and regional geochemistry. Cliff Walters, Mike Flagg, Connie Hellyer, Brock Toon, and Ruth Barrow completed analyses of the samples at the Mobil Technology Company geochemical laboratory. Mike Moldowan (Biomarker Technology, Inc.) assisted with mass spectrometry of the steranes.
AAPG Bulletin, V. 83, No. 12 (December 1999), P. 1927–1942.
is highly mature, and has undergone extensive migration fractionation. This oil probably originated from synrift-postrift Lower– Middle Jurassic Kembelangan Formation clay-rich shales that contained mixed type II/III kerogen deposited under oxic conditions. The huge gas reserves from the deep Wiriagar field were not analyzed but probably originated from Paleozoic source rocks. The shallow Wiriagar accumulation accounts for about 5% and the deep Wiriagar accumulation accounts for about 77% of the estimated ultimate recovery in eastern Indonesia. INTRODUCTION
In the southeast Asia-Australasia region, total estimated ultimate recovery of petroleum amounts to about 125 billion bbl of oil equivalent (BOE) [50 billion billi on bbl bbl oil, 125 125 tcf tcf (trillion (tril lion ft3) gas] (Howes, 1997). Petroleum systems in this large region are control led by the ma major tectonic brea br eakup kup of Gondwana in the Paleozoic and early Mesozoic. Our study area in eastern Indonesia (Figure 1) lies between the dominantly Tertiary petroleum systems on the Eurasian plate and the dominantly Paleozoic–Mesozoic systems on the Indo-Australian plate. The affinities of many crude oils in the study area were uncertain prior to our work. About one-half of the 38 basins in our eastern Indonesian study area remain undrilled (Sumantri and Sjahbuddin, 1994), and many other basins are poorly poorl y explored; explored; nevertheless nevertheless,, significa signifi cant nt amounts amounts of oil and gas are produced from the Salawati, Bintuni, and Bula basins. Geologists have speculated for many years that crude oils in eastern Indonesia originated mainly from Jurassic source rocks. Upper Jurassic marine source rocks generated about 25% of the world’s oil and gas (Klemme and Ulmishek, 1991). The Upper Jurassic source rocks of Australasia are generally not as prolific as other age-equivalent rocks (e.g., West Siberia, central Arabia, North Sea, Tampico, and Campeche). Howes (1997) estimated that only about 5% of the discovered oil and gas reserves in southeast AsiaAustralasia originated from Jurassic source rocks, but they are still significant sources for oil and gas. Examples include the Upper Jurassic Dingo Shale 1927
1928
Geochemistry of Eastern Indonesia Crudes
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Peters et al.
(Barrow-Dampier subbasin) and Flamingo Shale (Vulcan subbasin) in northwestern Australia (Bradshaw et al., 1997). Although limited to only a few oil samples, ten Haven and Schiefelbein (1995) inferred at least three petroleum systems in eastern Indonesia where the source rocks consist of Tertiary marine carbonates, Mesozoic marine carbonates, and Mesozoic marine siliciclastics. They found one Tertiary nearshore marine carbonate oil on the east coast of Sulawesi (Banggai), one Tertiary nearshore marine carbonate oil and one Mesozoic marine clastic oil in the Bintuni Basin, one Mesozoic marine carbonate oil on Seram, and one Mesozoic marine clastic oil on Timor. For this study, 27 crude oil and seep samples were collected from Irian Jaya, Seram, Sulawesi, and Timor in eastern Indonesia (Table 1, Figure 1) to better define petroleum systems in the area. A key aspect of the petroleum system approach is to identify the active source rock for each exploration play (Magoon and Dow, 1994); however, direct oil-tosource rock correlation commonly is not possible for various reasons. For example, samples of thermally mature prospective source rock may not be available (as in this study), or a few discrete rock samples may not accurately represent the vertical and horizontal compositional variations through a source rock interval that generated crude oil. The objectives of this geochemical study were to use high-resolution geochemical methods, including metastable reaction monitoring-gas chromatographymass spectrometry of biomarkers (Peters and Moldowan, 1993), to evaluate genetic relationships among these oils, their source rock age and paleoenvironment, and their relative thermal maturity and extent of biodegradation. Most biomarkers in crude oils are inherited from organic matter in their source rocks. Thus, biomarkers in crude oils allow the interpreter to reliably predict source rock characteristics, even when rock samples are not available. DISCUSSION
The following discussion briefly summarizes the petroleum geology of the key areas represented by samples in this study. The Salawati, Bintuni, and Bula basins are emphasized because of significant discoveries and production. Petroleum Geology of the Salawati Basin
The Salawati Basin is the most prolific oil basin in eastern Indonesia (Figure 1). About 300 million bbl of oil have been produced from 15 fields and more than 500 exploratory and development wells have been drilled. Howes (1997) estimated that
1929
about 500 million BOE will be recovered from the basin. Our estimate is slightly higher, about 700 million BOE. Walio and Kasim are the two largest fields with major production from Miocene reefal limestones of the Kais Formation and minor production from the U marker and Textularia II carbonates above the Kais Formation (Figure 2). Possible source rocks in the Salawati Basin include the Klasafet and Klamogun (Miocene), Sirga (Oligocene), Kembelangan (Cretaceous– Jurassic), Tipuma (Triassic), and Aifam (Permian) formations (Phoa and Samuel, 1986; Bradshaw et al., 1997, and references therein) (Figure 2); however, little evidence supports viable Mesozoic or Permian source rocks (e.g., Howes and Tisnawijaya, 1995). Most rocks of these ages in the basin are metamorphosed (Permian), missing (Jurassic), or show no generative potential (Cretaceous claystones). The MioceneKais(.) (. = hypothetical) petroleum system (sourcereservoir) in this basin is described as hypothetical because no geochemical correlations between the source and proven accumulations are available. Petroleum Geology of the Bintuni Basin
The first field in the Bintuni Basin (Figure 1) was not discovered until 1990. Howes (1997) predicted ultimate recoverable reserves of more than 1.5 billion BOE from the basin. Based on the recent discovery of huge deep gas reserves in the Wiriagar field, we estimate much higher ultimate recoveries near 3.5 billion BOE, including about 200 million BOE for the shallow oil in the Wiriagar field (Miocene Kais reservoir). Basement in the Bintuni Basin consists of metamorphic rocks of the Silurian or Devonian Kemum Formation. Middle Carboniferous–Upper Permian shallow-marine clastic rocks of the Aifam Group unconformably rest upon the basement. The Aifam Group consists of Aimau, Aifat, and Ainim formations. The lowermost Aimau Formation contains interbedded shallow-marine sandstones and shales. The overlying Aifat Formation is mainly Upper Permian calcareous marlstone and claystone. Conformably overlying the Aifat Formation, the Upper Permian Ainim Formation consists of fluvial deltaic and marine claystones, sandstones, coals, and carbonaceous shales. The Triassic– Jurassic Tipuma Formation unconformably overlies the Ainim Formation. The Tipuma consists of alternating fluvial sandstones and shales with minor evaporites deposited under continental and shallowmarine conditions. Lower–Middle Jurassic Kembelangen Formation marine deltaic shales [Inanwatan polysequence of Fraser et al. (1993)] probably are the best source rocks in the Bintuni Basin, but no oil-to-source rock
1930
Geochemistry of Eastern Indonesia Crudes
Table 1. Locations and Geochemical Data for Eastern Indonesian Oil Samples*
Abbrev.
Wiriagar Cendra Cendra91 Kasim Kl2_8510 Klalin Klamono LindaA5 LindaB Matoa SouthwO Jaya KasimB Kl2_8264 LindaT1 Minahak1 “Walid” Kolo Oil A Pt.Patri Walio AGL13S5 Bula E.Nief1 KS9016 Oil B Aliamb
Field
Wiriagar (GJ-90-F-115) Cendrawasih (91-D-055) Cendrawasih 91-D-055 Kasim Klalin 2 (8510) Klalin Klamono Linda A-5 Linda B Matoa Southwest O Jaya Kasim Barat (91-D-051) Klalin 2 (8264) Linda T-1 Minahaki 1 (91-B-150) Walio(?)(91-D-50) Kolo (91-C-247)
Group
1 2A 2A 2A 2A 2A 2A 2A 2A 2A 2A 2B 2B 2B 2B 2B 3 3 3 Pt. Patrindo (MOG-01-20) 3 Walio 3 AGL 13-S-5 (91-A-447) 4A Bula 4A East Nief 1 (90-m-207) 4A KS-90-16, SP680 4A 4A Aliambata 90-HS-58 4B
Location
Depth (ft)
API
Irian Jaya m 39 Irian Jaya m 28 Irian Jaya m 27 Irian Jaya m 37 Irian Jaya 8510–8536 35 Irian Jaya m 46 Irian Jaya m 19 Irian Jaya m 22 Irian Jaya m 18 Matoa(?) m 33 Salawati Seep 54 Irian Jaya m 36 Irian Jaya m 32 Irian Jaya 8264–8330 44 Irian Jaya m Solid Sulawesi m Small Irian Jaya m 27 Sulawesi m Solid Sulawesi m Solid Seram Seep m Irian Jaya m 33 Seram Seep 23 Seram Seep 23 Seram 5742–5790 19 Seram(?) Seep 24 Seram 7000–7028 15 Timor Seep 25
S (wt. %)
Pr nC17
Ph nC18
Pr Ph
13Csat
0.05 0.45 0.44 0.19 0.03 0.07 0.37 0.68 0.84 0.17 0.03 0.23 0.22 0.01 0.92 Small 0.37 1.21 1.25 0.08 0.30 1.27 1.11 2.00 0.94 2.95 0.08
0.53 1.38 1.36 1.08 0.90 1.03 m 2.12 m 0.66 0.67 1.01 0.97 0.92 m 0.96 1.28 m 1.00 0.41 1.28 m m 0.20 m 0.19 m
0.22 1.28 1.26 0.51 0.57 0.51 m 1.73 m 0.52 0.43 0.58 0.53 0.54 m 0.61 0.80 m 0.93 0.23 0.82 m m 0.32 m 0.41 m
2.56 1.17 1.16 2.18 1.83 2.22 m 1.35 1.24 1.29 1.84 1.96 1.90 2.35 m 2.22 1.72 m 1.13 2.21 1.72 0.77 m 0.74 0.48 0.51 1.58
–25.42 –19.65 –19.55 –21.68 –22.57 –22.71 –20.24 –21.09 –20.62 –19.57 –18.88 –21.26 –21.54 –21.83 –20.02 –21.36 –22.06 –22.11 –23.36 –22.07 –22.04 –28.70 –28.80 –28.68 –28.56 –28.68 –29.69
13Caro
–23.89 –19.56 –19.48 –20.91 –20.87 –21.01 –19.52 –20.16 –20.05 –18.96 –18.09 –20.93 –20.74 –20.32 –19.92 m –21.47 –21.24 –22.67 –20.40 –21.42 –28.42 –28.30 –28.97 –28.25 –29.10 –28.51
CV
–0.37 –5.36 –5.43 –3.22 –0.88 –0.84 –3.78 –3.05 –3.99 –4.23 –4.04 –4.33 –3.20 –1.53 –5.22 m –3.50 –2.86 –2.88 –1.10 –3.44 –2.13 –1.61 –3.40 –2.11 –3.69 0.17
*Pr = pristane, Ph = phytane; 13Csat and 13Caro = stable carbon isotope ratio (δ13C) for saturated and aromatic hydrocarbons, respectively, relative to PDB standard (‰); CV = canonical variable (Sofer, 1984) = – 2.53δ13Csat + 2.22δ13Caro – 11.65; %C27 = 100 × C27 /(C27 + C 28 + C 29) 5α,14α,17α(H), 20S + 20R and 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 regular steranes; %C27d = 100 × C27 /(C 27 + C28 + C29) 13β,17α(H), 20S + 20R diasteranes; %C30d = C30 /(C 27 + C28 + C29 + C30) ) 13β,17α(H), 20S + 20R diasteranes; %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) = C26 24nordiacholestanes 20S + 20R/(24- + 27-nordiacholestanes) (Holba et al., 1998); %1/(1 + 2 + 3) = 100 × rimuane/(rimuane + isorimuane + isopimarane) (Figure 8); Tet/(Tet + 26) = C 24 tetracyclic/(C24 tetracyclic + C26 tricyclic terpanes); Ol/(Ol + H) = oleanane/(oleanane + hopane); R o = calculated vitrinite reflectance equivalent (% Ro) based on calibration of methylphenanthrenes (Boreham et al., 1988); m = missing or unreliable. Most parameters are described further in Peters and Moldowan (1993).
correlation has been published. Other inferred or possible source rocks include the Pliocene Steenkool Formation, upper Miocene Klasafet Formation, and Permian Ainim and Aifat formations (Collins and Qureshi, 1977; Chevallier and Bordenave, 1986; Dolan and Hermany, 1988; Bradshaw et al., 1997). Little evidence is available to support viable Steenkool or Klasafet source intervals. The deep Wiriagar gasprobably originated from Paleozoic, possibly Permian, source rock (Bradshaw et al., 1997, and references therein). Petroleum Geology of the Banggai Basin, Sulawesi
thick claystones that provide a good regional seal. As early as 1985, gas and oil were discovered in Oligocene–Miocene reefal carbonates in the offshore Tiaka field located about 90 km southwest of Minahaki field in Figure 1. Subsequent discoveries have been mainly gas (e.g., Minahaki field). Possible source rocks in the Banggai Basin include lower Miocene carbonaceous shale and argillaceous limestone and Eocene bituminous limestone and shale (Kartaadiputra and Samuel, 1988). Deeper Mesozoic source rocks also may exist. Petroleum Geology of the Bula Basin, Seram
Tertiary rocks in the Banggai Basin (Tomori block) The offshore Bula field is the only producing along the eastern coast of Sulawesi consist of Paleogene field in Tertiary Bula Basin in eastern Seram (Figure carbonates overlain by Miocene shelf and reefal lime- 1). The Bula field produces 21–29° API oil from the stones. The overlying Pliocene sediments contain Pleistocene Fufa Formation (100–300 m depth).
Peters et al.
1931
Table 1. Continued. % C27
35.7 32.3 32.8 30.7 31.2 32.6 30.2 32.0 33.1 28.8 27.4 34.1 32.5 33.2 36.3 29.3 28.3 28.4 27.6 25.2 26.8 29.3 29.5 27.4 28.9 27.7 30.9
% C28
% C29
% C30
% C27d
% C28d
% C29d
% C30d
% 20S
% ββ
% Dia
Ster (ppm)
28.1 32.3 33.3 32.9 33.7 34.4 37.2 35.9 34.7 33.2 32.9 36.3 34.4 33.4 32.0 37.5 28.7 31.7 27.4 32.3 30.5 29.3 28.7 30.4 26.9 27.0 24.5
36.2 35.4 33.9 36.4 35.1 33.0 32.6 32.1 32.2 38.0 39.8 29.6 33.1 33.4 31.7 33.1 43.0 39.9 45.0 42.5 42.7 41.4 41.8 42.2 44.1 45.3 44.7
5.5 2.4 1.9 2.6 2.3 2.1 3.7 2.0 2.0 2.1 4.7 1.9 2.0 3.3 1.9 3.4 2.7 2.0 3.2 3.3 2.0 3.9 3.9 4.2 4.3 4.3 5.7
39.9 34.1 34.4 32.8 34.8 31.2 33.0 33.4 35.3 33.4 35.6 38.1 39.8 39.0 37.5 38.8 33.5 36.5 36.2 35.2 33.5 29.1 29.1 31.8 28.5 31.9 32.7
29.6 29.6 28.8 28.9 31.1 31.0 32.1 33.7 31.2 31.9 33.0 34.8 30.1 30.5 29.3 31.4 27.7 27.9 26.0 29.1 27.9 27.6 29.5 32.6 28.4 25.3 22.3
30.5 36.3 36.8 38.4 34.0 37.7 34.9 32.9 33.5 34.7 31.4 27.1 30.1 30.5 33.2 29.8 38.8 35.6 38.8 35.8 38.6 43.3 41.5 35.6 43.0 42.8 45.0
2.7 2.9 2.3 2.4 2.6 1.3 4.7 1.7 1.7 2.3 5.5 1.8 2.1 3.5 1.7 3.5 1.7 1.6 1.7 2.4 1.5 4.9 5.3 6.8 3.2 4.0 4.1
m 48.4 50.1 49.8 55.4 58.0 50.3 45.7 46.5 54.0 52.1 48.9 45.8 56.1 48.6 50.1 49.6 51.8 50.7 52.9 48.7 53.6 49.8 52.7 50.7 42.3 54.1
m 62.7 62.8 61.5 68.0 68.3 66.5 64.3 61.2 70.4 63.7 61.1 59.6 66.8 61.6 62.4 61.7 63.7 65.6 66.6 65.1 65.4 62.0 68.0 63.4 58.1 65.6
61.7 16.9 16.7 32.3 30.8 28.9 13.9 15.2 15.3 32.6 47.7 29.8 34.3 43.0 16.6 36.3 21.7 36.7 32.6 41.2 21.9 15.8 18.0 15.1 17.1 7.8 45.2
9.0 1264.2 1149.9 353.8 428.6 196.2 813.9 949.2 1448.5 321.7 34.4 222.4 286.4 33.8 1339.0 73.3 1035.3 914.2 331.6 133.1 1125.9 367.9 536.1 362.4 549.3 510.7 590.8
Estimated oil reserves from the field are about 14–16 million bbl (O’Sullivan et al., 1985). Middle Triassic–Lower Jurassic fluvial to brackish water sandstones and shales of the Wakuku beds or Kanikeh Formation are the oldest nonmetamorphosed rocks in the Bula area (Kemp and Mogg, 1992). The Wakuku beds overlie and interfinger with the deepmarine Saman-Saman Limestone. The bioclastic and oolitic Upper Triassic– Lower Jurassic Manusela Formation was deposited in shallower water and interfingers with both the Wakuku beds and the Saman-Saman Limestone. The Manusela Formation is unconformably overlain by Upper Jurassic–middle Miocene Nief beds. The Nief beds consist of claystone with abundant chert nodules, marlstone, and calcareous siltstone deposited initially under bathyal conditions but grading upward to shallow-shelf deposits. Gribi (1974) concluded that Tertiary or Triassic– Jurassic source rocks generated oils in the Bula Basin. Later work suggested that the oils originated from marine or nonmarine carbonate-evaporite source 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 source rocks (Fraser et al., 1993). Oil from the East Nief 1
Dia (ppm)
13.1 226.3 199.0 148.3 168.3 70.4 118.5 153.8 228.6 138.6 27.6 82.3 133.1 22.7 239.8 37.4 255.2 479.6 144.6 83.4 284.4 59.5 102.9 56.0 98.7 35.4 436.9
24 (1+2+3) (1+2+3) (1+2+3) Tet OL (24+27) (%) (%) (%) Tet+26 OL+H
0.38 19.56 11.99 68.45 0.25 14.95 78.14 6.91 0.26 12.16 81.10 6.74 0.29 16.71 75.23 8.06 0.30 15.54 77.05 7.41 0.26 20.27 71.56 8.17 0.25 15.77 64.58 19.64 0.29 11.00 78.00 11.00 0.25 13.28 80.21 6.51 0.27 17.77 72.35 9.88 0.40 17.62 71.36 11.02 0.29 15.90 78.95 5.15 0.25 13.50 81.23 5.27 0.32 17.74 75.51 6.75 0.26 16.73 76.05 7.22 0.35 22.40 64.81 12.79 0.31 20.72 70.37 8.91 0.28 17.60 66.96 15.44 0.28 17.90 70.47 11.63 0.35 33.61 52.73 13.66 0.27 19.69 73.28 7.03 0.22 35.92 10.20 53.88 0.24 43.94 6.58 49.48 0.29 36.00 13.33 50.67 0.24 36.36 7.79 55.84 0.24 35.06 11.80 53.15 0.15 41.67 21.41 36.93
m 0.62 0.63 0.63 0.50 0.52 0.56 0.63 0.64 0.54 0.54 0.61 0.64 0.48 0.62 0.74 0.51 0.57 0.63 0.68 0.52 0.91 0.89 0.92 0.88 0.92 0.61
m 0.70 0.70 0.64 0.72 0.73 0.59 0.68 0.67 0.58 0.60 0.60 0.66 0.59 0.66 0.49 0.46 0.36 0.46 0.24 0.48 0.00 0.00 0.00 0.00 0.00 0.00
Ro
0.98 1.27 1.28 1.18 0.93 0.92 1.08 0.98 1.00 1.10 1.35 1.07 1.40 0.91 1.01 0.85 1.01 0.77 0.76 0.83 1.01 0.89 0.87 0.86 0.50 0.71 0.69
well is produced from the Manusela Formation and probably originated from this source. Estimated ultimate recovery from the hypothetical MesozoicManusela(.) petroleum system in Seram is less than 100 million BOE (Howes and Tisnawijaya, 1995). Petroleum Geology of the East Timor Area
The tectonic evolution of Timor is poorly understood, but it is generally recognized that it originated on the Australian shelf. A major early(?) Miocene orogeny separates highly tectonized preorogenic flysch deposits from later postorogenic rocks and marks the time of complete separation from Australia. Petroleum seeps on the island probably originate from source rocks in the preorogenic sequence because it is unlikely that the Tertiary rocks were buried sufficiently to reach the oil window. The oldest preorogenic rocks consist of about 1500 m of Permian turbidites, limestones, and minor interbedded volcanics that crop out on eastern Timor. The Triassic Aitutu limestone is about 1000 m thick and is overlain by Jurassic marlstone that includes shales with turbidites and interbedded limestone near the top. Cretaceous–Eocene rocks
1932
Geochemistry of Eastern Indonesia Crudes
D O R P S T N E M E L E M E T S Y S M U E L O R T E P
N I S A B I N U T S N O S I N I T E N B A K M C
e n o t s e m i l m r o f t a l p d n a l a o h S
s , s l l e i f n n k i c s i a h t b e l d i b p i a a r R a v
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d n a t s e i s n i r o a p e m d e a r h o k h b s r a a s e N
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T E F A S A L K
I A M U A F
e d l e b a s i n r n o e a i t d v , n s u o e b c c i r t t s f n i i r e d n u y q S e s
e n l i l r i a f n i m p s a e b e D
R
R S
I P I R A W
N A G N A L E B M E K
S S A J
c i l e a r d e a t u s p i a t d l a b e t h d u g r b i a i r h w t o , t s s i c a d i r y t o l s l f e l a d i c W
t , , s e s n d o w e i o b t u t e d b i e r n r t l i s o a d r p t n e t e e l a b n i a n t i o n r b o a r C v a C
R S
R A M U P I T
U M T I A A N I F M I I A A A
Y G O L O H T I L E N E C O I M
T N E C E R
E G A
E N E C O I M
E N E C O E
E N E C O E L A P
E N E C O E
S U O E C A T E R C
R E P P U
C I S S A R U J
E L D D I M
C R I E S S W A O R L U J
D O R P S T N E M E L E M E T S Y S M U E L O R T E P
l l i f n i s a b d i p a r k c i h T
N I S A C R B S I T Y H A P A R G N W I A T A M A R A T S L S A O L K A H T I S L E L E
r l m a f o o t h l a s p d d n a a o r e b l c a n n o n s i P f e e r C S
T S L I I . T X E T T E F A S A L K
N S
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E N Y E E L C T R O A A L T E S I E L P E N E C O I L P Q
E T A L
, m r o f t a l s p f e y l t e r D n e N a n r A i a r S m o T d S e T r P
R
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S I A M F K
A M U A F
A G M R I F S
l a y h t a b l i - l f c n i i t i r s a e b n r e t u O N I K M S F M I
Y L R A E
E N E C O I M
N A I M R E P
I N O B R A C
S U O R E F
t f i c r t l e i s l a v a r i o t s p n s a / e a p s t f i n d c i r t n i t n n m y o - a s s c n s l a e c - - i a t i c c m i r m s i o e l s s s a o a P d r i u r J T S
R N E A B G M N E A K L
M A F I A
A M U P I T
M E T - A S E I D M E N K T E S M U M
N G U M O K LA
E L D D I M
C I S S A I R T
+ + + + + + + + + + T I A W A L A S T I R A S I S C
+ + + + + +
E T I N A R G
E T A L
Y L R A E
P E R I M A N S I L U R - O D E V O I N A N
N E C O E L A P E N E C O G I L O E N E C OE E
Y R A I T R E T
N I R T S U N O I T A L C E E R A T E C U O S
Y R A I T R E T - E R P
= R , k c o r e c r u o s = S . d e d n e t n i s i e l a c s l a c i t r e v o N . a i s e n o d n I n r e t s a e , s n i s a b i n u t n i B d n a i t a w a l a S r o f s n m u l o c c i h ) l p a a r e s g ( i t k a r c o t s r d p e a z c i l = a r C e , n k e c G o r — r i 2 o e r v r u e g i s F e r
Peters et al.
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
1933
Figure 3—Dendrogram shows genetic relationships among oils based on chemometric analysis of selected source-related geochemical data (Table 1). Cluster distance is a measure of genetic similarity indicated by the horizontal distance from any two samples on the left to their branch point on the right.
2B 3 4A 4B
consist of radiolarian claystone, calcilutite, variegated chert, and limestone. Postorogenic subsidence resulted in deposition of up to 4000 m of clastics in basins within the Timor area. Tertiary rocks in these basins consist mainly of deep-water carbonates overlain by up to 2000 m of Pliocene– Pleistocene clastics. Crostellaand Powell (1975) concluded that surface oil seeps in east Timor originated from Jurassic and Triassic source rocks. A hypothetical Mesozoic– Tertiary(.) petroleum system is inferred for Timor Island (Howes and Tisnawijaya, 1995; ten Haven and Schiefelbein, 1995; Bradshaw et al., 1997). Although more than two dozen wells have been drilled, no significant petroleum accumulations have been discovered. Geochemistry of the Oils
Chemometric analysis of source-related biomarker and stable carbon isotopic data was based on 13 source-related parameters for the oils as described in the Appendix, and resulted in four genetic groups (Figure 3, Table 1): Probable Lower–Middle Jur assic Oils Group 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 oil is nonbiodegraded based on unaltered n-paraffins, but shows evidence of evaporative loss of light ends and extensive migration fractionation as might occur during repeated retrograde condensations (Fi gure 4). The oil contains very low biomarkers (e.g., 9 vs. 34– 1449 ppm steranes for the other samples), which complicates the interpretation. The high pristane/phytane ratio (Pr/Ph = 2.56) and plot locations in Figures 5 and 6 indicate that the source rock for the shallow Wiriagar oil contains mixed terrigenous and marine type II/III organic matter deposited under oxic conditions. The stable carbon isotope, sterane, and tricyclic diterpane compositions for this oil are distinctive (Figures 6–8), suggesting that it was derived from a different source rock than the other oil samples. Although steranes and diasteranes are low, the high diasterane ratio [diasterane/(diasterane +regular steranes) = 62%] suggests that the shallow Wiriagar oil originated from a clay-rich clastic rock. Clay-rich source rocks generate low-sulfur oils that are enriched in diasteranes because clays are required to catalyze the transformation of steroids to diasteranes, and metals in the clays compete for sulfur that might otherwise be incorporated into
1934
Geochemistry of Eastern Indonesia Crudes
Figure 4—Representative gas chromatograms (left) and terpane mass chromatograms (m/z 191) (right) for the oil samples.
Gas Chromatograms
Terpane Mass Chromatograms
GROUP 1 Wiriagar
m/z 191 Pristane Phytane
GROUP 2A Southwest Obi
Oleanane Hopane
Oleanane
GROUP 2B Jaya
Hopane
Oleanane
Hopane
GROUP 3 Walio
Norhopane
GROUP 4A Oil B Phytane
the organic matter and generated oil (Peters and Moldowan, 1993). Conversely, clay-poor carbonate source rocks commonly generate high-sulfur oils with low diasteranes. The shallow Wiriagar oil lacks oleanane, consistent with a Jurassic or older marine source rock, and contains high 24-n-propylcholestanes (C30 steranes, Figure 9). Oleanane is a biomarker derived from angiosperms (flowering plants) that originated in the Cretaceous but did not dominate the land until the Tertiary (Peters and Moldowan, 1993; Moldowan et al., 1994). The C30 24-n propylcholestanes are diagnostic of marine source rock depositional environments (Moldowan et al., 1985; Peters et al., 1986). The isotopic compositions of the saturated and aromatic hydrocarbons
Hopane
Tricyclic Terpanes
for this oil (Figure 6) are consistent with a Mesozoic source rock but are not typical of Tertiary or Paleozoic oils (Chung et al., 1992). On this basis, a Permian source for the shallow Wiriagar oil is unlikely. The high C26 24-nordiacholestane ratio for the shallow Wiriagar oil (0.38, Table 1) would normally indicate a Cretaceous or younger source rock age (Holba et al., 1998); however, this high value for shallow Wiriagar oil is not reliable because of low biomarker concentrations. The East Onin 1 well from the Babo block in the Bintuni Basin (Harrington, 1996) (Figure 1) is located near the Wiriagar field. This well contains about 350 m of highly mature Lower– Middle Jurassic Kembelangan source rock with high residual total organic carbon (total organic carbon or TOC ≈
Peters et al.
100
7 10 1
C n / e n a t s i r P
I II e p y s T u o ig e n r r I T e I I /I I e T y p d e M i x e I I p y a l T g l A in e r a M
Group 1 2 3 4
O x i d i z i n g
1
0.1 0.1
R e d u c i n g
1
E. Nief1 Oil B
1935
Figure 5—Plot of pristane/n-C17 vs. phytane/n-C18 from whole-oil chromatograms can be used to infer oxicity and organic matter type in the source rock depositional environment. Increasing thermal maturation and biodegradation displace points toward the lower left and upper right, respectively.
10
Phytane/n C18
) 4 8 1 9 ( r f e o S
-17 -19
Terrigenous
s c -21 i t a m o r -23 A
C 3
Wiriagar
Group 1 2 3 4
1 -25 δ
Marine
-27 Aliambata
Figure 6—Stable carbon isotope ratios (‰relative to PDB standard) for saturated vs. aromatic hydrocarbons differ between oil groups and can be used to infer the relative amounts of terrigenous vs. marine organic matter in their source rocks. The dotted line, showing best separation, is based on a statistical analysis of hundreds of known marine and terrigenous crude oils (Sofer, 1984).
-29 -31 -31
-29
-27
-25
-23
-21
-19
-17
δ1 3CSaturates 1.5–2.5 wt. %). Rock-Eval pyrolysis hydrogen indices in this interval are low (∼90 mg HC/g TOC) but were probably higher (∼200 mg HC/g TOC) prior to thermal maturation. This shale-rich interval probably generated large amounts of wet gas and some oil and
could be the source for the shallow Wiriagar oil. High methylphenanthrene and diasterane ratios combined with low biomarker concentrations suggest a maturity past peak oil window (∼1.0%Ro) for the shallow Wiriagar oil (Table 1), which is similar to
1936
Geochemistry of Eastern Indonesia Crudes
Figure 7—Ternary diagram of C27, C28, and C29 sterane composition for oils based on high-resolution biomarker analysis (metastable reaction monitoring-gas chromatography-mass spectrometry). Chemical structures are shown at left. The corners of the triangle represent the relative percentage of the corresponding sterane homolog.
70% C27 Steranes
X
Group 1 2 3 4
X = H, CH3, C2H5
70% C28
Figure 8—Ternary diagram of relative percentages of three tricyclic diterpanes in oils (rimuane, isorimuane, and isopimarane structures at left) based on high-resolution biomarker analysis (metastable reaction monitoring-gas chromatography-mass spectrometry). The stereochemistries of the rimuane isomers are not known. The corners of the triangle represent 100% of the corresponding tricyclic diterpane.
70% C29
100% 1/(1+2+3)
Diterpanes 1 = Rimuane 2 = Isorimuane?
Group 1 2 3 4
3 = Isopimarane Aliambata
100% 2/(1+2+3) that in the Kembelangan interval from the East Onin 1 well (Tmax ≈ 460–470°C, Ro ≈ 1.0–1.3%). The Bintuni Basin is likely to contain at least one additional 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 to originate from a Permian source (Dolan and Hermany, 1988). These oils were not available for our study.
100% 3/(1+2+3) Tertiar y Mar ine Marlstone Oils Groups 2 and 3 consist of geochemically similar oils that contain oleanane and originated from marine marlstone source rocks of Tertiary age. Group 2 oils are mostly from the Salawati Basin in Irian Jaya (Figure 3). 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 near Irian Jaya). Subgroup 2B consists of oils from Jaya,
Peters et al.
Aliambata Wiriagar
Group 1 2 3 4
5
s e n a r 4 e t S
Tertiary Oils TriassicJurassic Oils
0 3
C 3 % 2 0
0.2
0.4
0.6
Ol/(Ol + H) Linda T1, Klalin 2 (8510 ft; 2595 m depth), and Kasim Barat (Irian Jaya) and Minahaki 1 (Sulawesi). Group 2 and 3 samples show high oleanane ratios and 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 diagnostic of Tertiary source rock (Moldowan et al., 1994). Another age-related biomarker ratio provides independent support for the interpretation of Tertiary source rock. All group 2 and 3 oils show high 24-nordiacholestane ratios (0.25–0.40 and 0.27–0.35, respectively, Table 1), where ratios greater than 0.25 are diagnostic of oils from Cretaceous or Tertiary source rocks (Holba et al., 1998); furthermore, the saturated and aromatic hydrocarbons for group 2 and 3 oils are enriched in 13C (Figure 6), typical of Oligocene–Miocene rather than Mesozoic oils (Chung et al., 1992). Group 2 and 3 oils show no evidence for significant contamination by nonindigenous oleanane. Such contamination is rare because biomarkers in migrating oils commonly overwhelm the comparatively small amounts of contaminants in organiclean carrier beds and reservoir rocks (Peters and Moldowan, 1993). If oleanane were a contaminant solubilized by migration of mature oil through less mature carrier beds, one would expect mixed maturity signals depending on the origin of the compounds used for each maturity parameter; however, the 18α/18β oleanane stereoisomer ratios for these oils are consistent with independent maturity parameters from other biomarkers in the samples; furthermore, as discussed in previous paragraphs, all of the oils that show high oleanane ratios also show high 24-nordiacholestane and
13C-rich
1937
Figure 9—Plot of oleanane vs. C30 sterane (24-n-propylcholestane) ratios separates oil groups. Oleanane ratios for oils greater than 0.20 indicate Tertiary source rocks (groups 2 and 3), whereas the absence of oleanane is consistent with a Jurassic or older source (group 4). C30 24-n-propylcholestanes are diagnostic of marine source rock depositional conditions. The C30 sterane ratio generally increases with marine vs. terrigenous organic-matter input to the source rock. Wiriagar oil is problematic because biomarkers are low. This oil lacks oleanane but shows high C30 steranes.
isotope ratios, consistent with a Tertiary age for their source rocks. The Klamono (0.37 wt. %sulfur, 19° API, Table 1) and Linda T1 (0.92 wt. %sulfur, solid) oils are moderately biodegraded based on the absence of n-paraffins and 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 the lack 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 (0.44–0.45 wt. %sulfur, 27–28° API) show evidence of very mild biodegradation of n-paraffins (level 1). Nonbiodegraded group 2 oils show Pr/Ph ratios in the range from 1.29 to 2.35, low sulfur (0.01–0.23 wt. %, Table 1), and isoprenoid to n-paraffin ratios that indicate an origin from mixed type II/III organic matter deposited under suboxic conditions (Figure 5). The stable carbon isotope compositions of saturated and aromatic hydrocarbons for these oils (Figure 6) and the resulting calculated canonical variables (CV, see Table 1) indicate mostly marine organic matter in their source rocks. Most group 2 and 3 oils show moderate diasterane ratios (20–40%, Table 1), suggesting a calcareous claystone or marlstone source rock with clay content between pure carbonate and clay-rich siliciclastic. We use the term “marlstone” to describe the lithology of the source rock for most oils in these two groups. Some group 2 oils, such as the Linda A5, 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
1938
Geochemistry of Eastern Indonesia Crudes
(54°) because it is very mature based on the methylphenanthrene ratio (1.35%Ro equivalent, Table 1). Group 3 consists of oils from Walio, “Walid” (I rian Jaya), Kolo, Oi l A (Sulawesi), and Point Patrindo (Seram). These oils are geochemically similar to group 2 oils (Figures 5–8), but show lower oleanane ratios (Figure 9), which still exceed 0.20 and thus are diagnostic of Tertiary source rocks. The Kolo oil is moderately biodegraded based on absence of n-paraffins and isoprenoids but unaltered steranes (level 5) (Peters and Moldowan, 1993). This sample is a solid that contains high sulfur (1.21 wt. %) due to the biodegradation. Oil A is also a solid with high sulfur (1.25 wt. %), which shows evidence of very mild biodegradation of n-paraffins (level 1–2). Nonbiodegraded group 3 oils show low sulfur (0.08–0.37 wt. % sulfur) and moderate API gravity (27–33° API), similar to the nonbiodegraded group 2 oils.
Biomarker and other parameters for the subgroup 4A oils are consistent with an anoxic marine carbonate source rock. For example, these oils show low diasterane ratios (8–18%, Table 1), low tricyclic terpanes, high norhopane/hopane ratios (e.g., Oil B in Figure 4), high 30-norhopanes, and high sulfur (0.94–2.95 wt. %), consistent with a clay-poor anoxic carbonate source rock (Subroto et al., 1992; Peters and Moldowan, 1993). The high Pr/Ph ratio (1.58) and low sulfur (0.08 wt. %) for the Aliambataoil suggest asuboxic source rock depositional environment. The high diasterane ratio for the Aliambata oil (45%, Table 1) indicates a clay-rich source rock, which is supported by the low sulfur content. Stable carbon isotopic compositions for the saturated and aromatic hydrocarbon fractions of the group 4 oils are depleted in 13C compared to the other oils in the study and are typical of Mesozoic rather than Oligocene–Miocene oils (Chung et al., 1992) (Figure 6). The plot location for these oils in Figure 6 and their calculated canonical variables (CV, see Table 1) indicate mainly marine source rock organic matter. The Aliambata oil shows a higher CV than the other group 4 oils (0.17 vs. –1.6 to –3.7), suggesting that its source rock received more terrigenous organic matter. The group 4 oils are enriched in C29 steranes compared to most other samples in the study (Figure 7), suggesting that their source rock received greater higher plant input; however, the composition of the higher plants that contributed to the group 4 oils was distinct from that of the other groups. For example, the group 4 oils show different distributions of tricyclic diterpanes than the other groups (Figure 8) and lack oleanane (Figures 4, 9). Lack of oleanane indicates an absence of flowering higher plants and suggests that the source rock is Jurassic or older. Except for the E. Nief 1 oil (0.29), most group 4 oils show low C26 24-nordiacholestane ratios (0.15–0.24, Table 1), consistent with a Jurassic or older age (Holba et al., 1998). The group 4 oi ls contain more C30 24-n propylcholestanesthan most oils in the study except Wiriagar oil, suggesting strongly marine depositional conditions for the source rock (Figure 9). The Aliambata oil shows a higher C30 24-npropylcholestane ratio than the other group 4 oils, consistent with other data that indicate Aliambata oil is different from the other group 4 oils. Table 2 summarizes key geochemical parameters for each oil group and the inferred characteristics of their source rocks.
Tri assic– Jurassic Oils Group 4 contains two genetic subgroups; both subgroups are characterized by lack of oleanane. Subgroup 4A consists of oils from the Bula Basin in eastern Seram, including Bula, AGL13S5, KS-90-16, East Nief 1, and Oil B. Subgroup 4B consists of the Aliambata seep oil from eastern Timor Island. A Mesozoic source rock was previously inferred for oils from Timor and Seram (Price et al., 1987; ten Haven and Schiefelbein, 1995). Although mildly biodegraded (level 1) (Peters and Moldowan, 1993), the Pr/Ph ratio and biomarker characteristics of the Aliambata oil are similar to published data 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) is moderately biodegraded based on absence of n-paraffins and isoprenoids but unaltered steranes (level 5) (Peters and Moldowan, 1993). Oil seep samples AGL13S5, KS9016 (0.44–1.27 wt. % sulfur, 24–25° API) and Aliambata (0.08 wt. % sulfur, 25° API) are mildly biodegraded based on lack of n-paraffins but unaltered isoprenoids (level 2–3). Oil B shows high sulfur (2.95 wt. %) and low API gravity (15° API) because of low thermal maturity (Figure 10). The subgroup 4A oils are distinguished by very low Pr/Ph ratios (0.48–0.77), high sulfur (0.94–2.95 wt. %), and low API gravity (15–24° API) (Table 1). The Pr/Ph ratio could not be measured for the biodegraded Bula seep oil. Low Pr/Ph ratios (<1) and high sulfur (>0.5 wt. %) for oils are characteristic of highly reducing or anoxic source rock depositional conditions. The East Nief 1 oil and Oil B show Pr/ n-C17 and Ph/n-C18 ratios consistent with an origin from marine type II CONCLUSIONS source rock deposited under highly reducing to anoxic conditions (Figure 5). The remaining seep oils lack Only 7 of the 27 oil samples in this study origireliable n-C17 and n-C18 peaks due to biodegradation. nated from Triassic– Jurassic source rocks. These
Peters et al.
75 Matoa
70
KS9016
R 0 2 65
Klamono
Cendra91 Walio
β β
LindaA5
9 2
LindaB Oil B
Jaya KasimB
Oil A
Cendra
LindaT1
C 60 %
KI2_8510
E. Nief 1
Klalin
Pt.Patri KI2_8264 Aliambata AGL13S5
Minahaki1 Bula Kasim Kolo, Southw O “Walid”
Group 1 2 3 4
55
50 40
45
50
%C 29 αα20S seven oils, designated Wiriagar, Bula, Oil B, East Nief 1, AGL, KS9016, and Aliambata, occur in the southern portion of the study area on Seram (five oils), Timor (one oil), and Irian Jaya (one oil). Lowsulfur, high API gravity Wiriagar oil from Irian Jaya is nonbiodegraded, highly mature, and geochemically distinct from the other oils. The geochemical composition of the oil suggests that it originated from a pre-Cretaceous marine clay-rich clastic source rock that contained mixed type II/III organic matter, probably Lower– Middle Jurassic Kembelangan Formation [Inanwatan polysequence of Fraser et al. (1993)]. Samples designated Bula, Oil B, East Nief 1, AGL, and KS9016 show high sulfur and low API gravity and originated from type II organic matter in an anoxic marine carbonate source rock. Lowsulfur Aliambata oil originated from a marine clastic source rock that contained mixed type II/III organic matter deposited under more oxic conditions. The source rock for the Aliambata oil was a more terrigenous-influenced, shaly equivalent of the marine carbonate source rock. The Aliambata oil is geochemically similar to Upper Jurassic Dingo Claystone oils from Western Australia. The source rocks for these six oils are probably synriftpostrift shales and carbonates like those in the Lower–Middle Jurassic Kembelangan Formation in the Bintuni Basin or Triassic carbonates on Buru Island. The remaining 20 oils in the study originated from Tertiary source rocks based on high oleanane and C26 24-nordiacholestane ratios; furthermore,
55
60
1939
Figure 10—Oil samples show a range of thermal maturity based on two maturity-related biomarker parameters [%20S/(20S + 20R) and %ββ/(ββ +αα), Table 1]. Shaded areas represent end-point values where further maturation does not significantly increase ratios. Samples in the shaded area are near or past peak oil generation. Plot location for Wiriagar oil is problematic because of low steranes. High methylphenanthrene and diasterane ratios combined with low biomarker concentrations suggest a maturity near peak oil window (∼1.0% Ro) for the Wiriagar oil.
the 13C-enriched stable carbon isotope compositions of these oils typify Oligocene–Miocene oils. These oils are found in the northern portion of the study area near Irian Jaya (16 oils), Sulawesi (three oils), and Seram (one oils). Oils from Matoa, Linda B, Linda A5, Linda T1, Klamono, Klalin, Klalin 2 (8264 ft; 2520 m depth), Klalin 2 (8510 ft; 2595 m depth), Cendrawasih, Cendrawasih 91 D-055, Jaya, Kasim, Kasim Barat, Southwest O (Irian Jaya), and Minahaki 1 (Sulawesi) originated from a marine marlstone source rock. This source rock contained mixed type II/III organic matter deposited under suboxic conditions. Oils from Walio, “Walid” (Irian Jaya), Kolo, Oil A (Sulawesi), and Point Patrindo (Seram) are geochemically similar to these oils but show lower oleanane ratios. These oils probably originated from upper Miocene Klasafet Formation source rocks. We estimated the ultimate volumes of recovered petroleum contributed by each of the oil groups in eastern Indonesia. Estimated ultimate recoverable reserves in the study area are about 4.3 billion BOE (bbl of oil equivalent), assuming that the Bintuni, Salawati, Bula, and Banggai basins will produce about 3.5 billion, 700 million, 100 million, and 15 million BOE, respectively. The shallow and deep Wiriagar accumulations account for about 0.2 and 3.3 billion BOE, respectively; therefore, the inferred Lower– Middle Jurassic Kembelangan source for shallow Wiriagar oil (group 1) accounts for about 5%, and the deep Wiriagar accumulation, presumed to originate from Paleozoic source rock, accounts for about 77% of the estimated ultimate
1940
Geochemistry of Eastern Indonesia Crudes
Table 2. Summary of Measured Oil Properties and Inferred Source Rock Characteristics
Group 1*
Group 2**
Measured Oil Properties§§ Pr/Ph 2.6 1.2–2.4 Wt. %Sulfur 0.1 0–0.2 39 32–37 °API –25.4 –18.9 to –22.7 δ13C (‰) OL(OL +H) 0 0.49–0.73 24/(24 +27) 0.38 0.25–0.39 Inferred Source-Rock Characteristics Age Lower–Middle Jurassic Miocene Lithology Marine clay-rich clastic Marine marlstone Redox Oxic Suboxic Kerogen Type II/III Type II/III
Group 3† 1.1–2.2 0–0.4 27–33 –22.1 to –23.4 0.24–0.48 0.27–0.35
Group 4A†† 0.5–0.8 0.9–3.0 15–24 –28.6 to –28.8 0 0.22–0.29
Group 4B§ 1.6 0.1 25 –29.7 0 0.15
Miocene Triassic– Jurassic Triassic– Jurassic Marine marlstone Marine carbonate Marine shale Suboxic Anoxic Suboxic 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).
recovery in the study area. The Tertiary oils from the Salawati and Banggai basins (groups 2 and 3) and the Triassic– Jurassic oils from Seram and Timor (group 4) account for about 16 and 2%, respectively, of estimated ultimate recovery in the study area. APPENDIX: METHODS Bulk Properties Crude oil API gravity was determined at 15.6°C (60°F) by pycnometry. Sulfur was measured by ASTM standard test method D-5453 using an Antek 771 Pyroreactor™ coupled with an Antek 714™ ultraviolet sulfur detector. Samples were introduced into the pyroreactor using an Antek 735™ syringe drive to ensure reproducibility. The method accurately determines sulfur contents ranging from 1 ppm to 8 wt. %in liquid hydrocarbons with boiling temperatures ranging from 25 to 400°C.
Liquid Chromatography Hexane was added to the whole oil, and precipitated asphaltenes were removed using a cartridge filter. Saturated and aromatic hydrocarbon fractions were separated from the remaining oil by high-performance liquid chromatography (HPLC), using refractive index and ultraviolet detectors as described in Peters and Moldowan (1993).
Gas Chromatography-Mass Spectrometry Metastable reaction monitoring-gas chromatography-mass spectrometry (MRM-GCMS) and gas chromatography-mass spectrometry (GCMS) were used to analyze steranes and terpanes in the C15+ saturated hydrocarbon fractions of the crude oils. Semiquantitative GCMS analysis of terpanes was achieved using a Hewlett Packard 5890 Series II ™ gas chromatograph coupled either to a Hewlett Packard 5970™ or Hewlett Packard 5972™ mass spectrometer. Oils were spiked with 500 µL of a hexane solution 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 liquid chromatography (HPLC) group-type separation. Because neither compound is found in oils, the addition of 5 µg of each serves as an internal standard. Cholane behaves in the mass spectrometer in the same manner as steranes and other saturated polycyclic biomarkers. Its presence in an oil allows compensation for sample loss, biomarker fractionation, and variations in injection technique, gas chromatographic performance, and mass spectrometric sensitivity. Response factors for individual biomarkers relative to specific ions and the cholane internal standard vary with instrument conditions and thus are difficult to determine; therefore, the terpane quantification assumes that all compounds produce a response of unity. Using this approach, the quantities of terpanes were calculated as relative rather than absolute values. High-resolution quantitative MRM-GCMS analysis of steranes was achieved by analysis of aliquots of the spiked saturated hydrocarbon fraction described using a VG 7070E-HF™ double focusing magnetic sector instrument (Biomarker Technology, Inc.). Response factors for individual compounds were used to quantify absolute amounts of steranes and diasteranes in the samples. Detailed procedures and compound identifications for steranes and terpanes are in Peters and Moldowan (1993).
Gas Chromatography Gas chromatograms (GC) of w hole oils were run using a Hewlett Packard 5890™ gas chromatograph equipped with a flame ionization detector and a 30 m × 0.32 mm i.d. J&W DB-1 HT™ column (0.1 µm film thickness). The GC was temperature programmed from –15 to 340°C at 25°C/min and held at 340°C for 10 min using helium as the carrier gas.
Stable Carbon Isotopes Stable carbon isotope ratios (δ13C) were measured on C15+ saturated and aromatic hydrocarbon fractions using a Finnigan Delta E™ isotope ratio mass spectrometer and methods described by Schoell et al. (1983). Data are reported in parts per thousand (‰)
Peters et al.
relative to the PDB standard. The NBS-22 oil standard was used for calibrations and measures –29.75 ±0.05‰relative to PDB.
Multivariate Statistics Statistical analysis of multivariate geochemical data was completed using a commercial chemometrics program (Pirouette Version 2.03, Infometrix Inc.). Thirteen source-related geochemical 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, %C24 tetracyclic/ (C24 tetracyclic + C26 tricyclic) terpanes, and oleanane/(oleanane + hopane) ratios (Table 1). Exploratory data analysis, including computation and graphical display of the patterns of association in the data set, was completed using hierarchical cluster analysis (autoscale preprocessing, Euclidean metric distance, incr emental li nkage) and pri nci pal component analysis (autoscale preprocessing).
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Geochemistry of Eastern Indonesia Crudes
ABOUT THE AUTHORS Ken E. Peters
Budi Rustanto
Ken Peters is an associate geochemical advisor at Mobil Technology Company with 21 years of experience in worldwide exploration and development. He serves as associate editor for the AAPG Bulletin and Organic Geochemistry and was chairman of the prestigious Gordon Conference on Organic Geochemistry in 1998. He and J. M. Moldowan are co-authors of The Biomarker Guide. Peters has authored or co-authored over 80 articles on petroleum geochemistry.
Budy Rustanto received a B.S. degree in geology at the Pembangunan National University Yogayakarta (1986). He is currently working in the Regional Evaluation Exploration section for the State Oil and Gas Mining Company (PERTAMINA), Foreign Contractor Management Body (BPPKA) Jakarta. Budi is a member of the Indonesian Association of Geologists (IAGI).
Tom H. Fraser
Tom Fraser is a geoconsultant with Unocal in Jakarta, Indonesia. He has more than 12 years of experience in southeast Asia, especially in eastern Indonesia for Mobil , Conoco, and Maxus. His special interests include graphical petroleum system presentations through his company Resource System Diagnostics. Tom gained his bachelor’s degree in geology from QMC, London 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 a senior staff geologist in the Exploration (Geoscience) Department of Mobil Oil Indonesia, Inc. Jakarta. Before he joined Mobil in 1985 as a production geologist, he previously had worked with Maxus Energy for four years in Jakarta. He received his B.Sc. degree in geology from Bandung Institute of Technology (ITB) in 1981. He is a member of the AAPG and an active member of the Indonesian Petroleum Association (IPA), as well as the Indonesian Association of Geologists (IAGI).
Eddy Hermanto
Eddy received a B.S. degree in geology at the Pembangunan National University Yogayakarta (1987). He is currently working in the Regional Evaluation Exploration section for the State Oil and Gas Mining Company (PERTAMINA), Foreign Contractor Management Body (BPPKA) Jakarta. Eddy is a junior member of the AAPG, Indonesian Association of Geologists (IAGI), and Indonesian Petroleum Association (IPA).
