Oil-source correlations as a tool in identifying the petroleum systems of the southern Taroom Trough, Australia

Pergamon

Org. Geochem. Vol. 29, No. 1-3, pp. 713-734, 1998 ~) 1998 ElsevierScienceLtd. All rights reserved Printed in Great Britain P I h S0146-6380(98)00132-6 0146-6380/98/$- see front matter

Oil-source correlations as a tool in identifying the petroleum systems of the southern Taroom Trough, Australia K H A L E D R. A L - A R O U R U ' - ' t , D A V I D M. M C K I R D Y ' * and C H R I S T O P H E R J. B O R E H A M 3 'Organic Geochemistry in Basin Analysis Group, Department of Geology and Geophysics, University of Adelaide, Adelaide SA 5005, Australia, ~National Centre for Petroleum Geology and Geophysics, University of Adelaide, Adelaide SA 5005, Australia and 3Australian Geological Survey Organisation, GPO Box 378, Canberra ACT 2601, Australia

Abstract--A geochemical study of crude oils and samples of various Permian, Triassic and Jurassic organic-rich rock units from the southern Taroom Trough was undertaken to test the prevailing Permian-source hypothesis for the petroleum reserves of the Bowen/Surat Basin. Seventy three core and cuttings samples were screened using organic petrography, total organic carbon analysis, Rock-Eval pyrolysis, and solvent extraction. Saturated and aromatic hydrocarbon fractions of selected source rocks, kerogen hydrous pyrolysates, and thirteen oils were then analysed by gas chromatography, gas chromatography mass spectrometry and isotope ratio mass spectrometry, for the purpose of oil-tosource correlation. On the basis of their bulk carbon isotopic compositions and terpane, sterane and aromatic biomarker signatures, two oil families were identified. Those oils sourced by the Snake Creek Mudstone and reservoired in the Showgrounds Sandstone (both of Middle Triassic age) at Roswin North and Rednook are assigned to the "Snake Creek-Showgrounds" petroleum system. The remaining oils belong to the "Blackwater-Precipice" system. These originated in the Late Permian coal measures of the Blackwater Group but are produced from the Precipice Sandstone and other reservoir rocks of Permian to Jurassic age along the southeastern and southwestern margins of the trough. © 1998 Elsevier Science Ltd. All rights reserved Key words--oil-source correlation, terpanes, steranes, carbon isotopes, petroleum system, Taroom Trough

INTRODUCTION

the latter paper, the Middle Triassic Moolayember F o r m a t i o n is identified as a potential source rock for petroleum, and based on its light carbon isotopic composition, the R e d n o o k oil has been related to a Triassic source (Boreham, 1995). However, the lacustrine Snake Creek Mudstone, a member of the Moolayember Formation, is better known as a laterally-continuous seal which effectively forms a barrier to vertical migration from established Permian source rocks (Golin and Smyth, 1986). Hydrocarbon accumulations in the overlying Triassic and Jurassic formations suggest the existence of a source (or sources) other than the Permian, as long lateral and vertical migration paths have traditionally been considered unlikely (Thomas et al., 1982). The Snake Creek Mudstone is the most mature of the possible alternative sources, although its true hydrocarbon-generating potential has not yet been adequately evaluated. This paper reports the results of a geochemical study designed to assess the relative contributions of Triassic and Permian source rocks in the southern T a r o o m Trough to the oil reserves of the Bowen/Surat Basin. In particular, a detailed investigation of the Triassic Snake Creek Mudstone and the Permian Back Creek and Blackwater Groups

The first commercial hydrocarbon resources in Australia were discovered in 1900 at R o m a in the Surat Basin (Elliott and Brown, 1989). The Surat and Bowen Basins (Fig. l a) together comprise one of Australia's more prospective onshore petroleum provinces and both are important producers of oil and gas. The Bowen Basin also hosts large reserves of steaming coal. Over one hundred oil and gas discoveries have been made in these basins, most of them located along the eastern and western margins of the southern T a r o o m Trough (Fig. lb). The origin of these petroleum occurrences has been of interest to local explorers for more than 30 years, and is still being debated. The major effective source rock units in the Bowen/Surat province are considered by many researchers to be confined to the Permian section (Fig. lc, Thomas et al., 1982; Hawkins et al., 1992; Boreham, 1995; Carmichael and Boreham, 1997). In *To whom correspondence should be addressed. Tel.: +61-8-8303-5378; Fax: +61-8-8303-4347; E-mail: [email protected]. tPresent address: School of Earth Sciences, Macquarie University, NSW 2109, Australia. 713

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Petroleum systems of the southern Taroom Trough, Australia was undertaken, based on organic petrography, total organic carbon analysis, Rock-Eval pyrolysis, solvent extraction and biomarker analyses of saturated and aromatic hydrocarbons in representative samples from 43 exploration wells (Fig. lb). Sealedtube hydrous pyrolysis was also carried out on kerogens isolated from end-member Snake Creek organic facies and the resulting pyrolysates were compared with the extracts and oils in terms of their biomarker and carbon isotopic compositions. Thirteen petroleums were sampled and analysed chemically and isotopically for the purpose of oilsource correlation. The overall aim of this study was to explain the observed distribution of oil and gas throughout the Taroom Trough in the context of petroleum systems, with a view to delineating those areas most prospective for further discoveries.

GEOLOGICALSETTING The Taroom Trough was initiated as a foreland basin during the latest Carboniferous or Early Permian in response to a compressive force accompanying subduction along Australia's eastern continental margin (Middleton and Hunt, 1989). The trough is the eastern depocentre of the Bowen Basin, and is bounded by the BurungaGoondiwindi Fault System in the east and the Walgett-Roma Shelf in the west (Fig. la and b). The thickness of its Permo-Triassic sedimentary succession exceeds 9 km along its N - S axis in the central part of the southern Taroom Trough (Totterdell et aL, 1992). The sequence (Fig. lc) comprises shallow marine and terrestrial sediments, including thick deposits of black coal. The southern portion of the Taroom Trough (between latitudes 25°S and 29°S) covers an area of ca. 50,000 km 2 and is unconformably overlain by the JurassicCretaceous Surat Basin succession. The Back Creek Group section (~3 km thick) comprises shallow marine to paralic carbonates, siliciclastic and volcaniclastic sediments (Fielding et al., 1990). The overlying Gyranda Formation was deposited during a marine transgression. The ensuing regression led to deposition of extensive coal and carbonaceous facies of the Blackwater Group in alluvial plain, deltaic and paralic settings (Totterdell et al., 1992). Deposition of Early Triassic, fine-grained, red beds (Rewan Group) was followed by about 5 km of Middle Triassic sediments comprising the Showgrounds Sandstone, Snake Creek Mudstone and Moolayember Formation which accumulated in fluvial, lacustrine and fluviodeltaic environments, respectively. A predominantly freshwater lacustrine depositional setting is inferred for the Snake Creek Mudstone on the basis of its lithofacies, sedimentary structures, microflora and organic facies (Hawkins et al., 1992; A1-Arouri, 1996). After major Late Triassic uplift and erosion, renewed

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subsidence led to the accumulation of up to 2.7 km of fluvio-lacustrine and shallow marine sediments in the overlying Surat Basin during the Jurassic and Early Cretaceous (Fig. lc; Thomas et aL, 1982; Elliott, 1993).

SAMPLES AND METHODS Seventy three core and cuttings sample s of potential source rock (mudstone, siltstone, shale and coal), ranging in age from Early Permian to Middle Jurassic, were chosen from 43 exploration wells located throughout the southern Taroom Trough (Fig. lb and c). Particular attention was paid to the Snake Creek Mudstone which was sampled in 40 wells. Twelve oils and one condensate from reservoirs of Permian to Jurassic age in the Surat and Bowen Basins were selected for the purpose of oilsource correlation (Fig. lb and c). All rock samples were subjected to screening analyses, including determination of total organic carbon (TOC) content using a Leco carbon analyser, and Rock-Eval pyrolysis using a Girdel IFP-Fina Mark 2 instrument (Model 59). Polished sections mounted in araldite resin were examined under reflected white light and UV-excitation using a Leitz Ortholux II microscope fitted with oil immersion objectives. Maceral analysis was performed in accordance with the Australian Standard AS 2856 (Standards Association of Australia, 1986). To further illustrate the nature of the organic matter in some samples, a Philips 1000 scanning electron microscope was utilised. Bitumen, or extractable organic matter (EOM), was extracted from powdered rock samples (up to 50 g) with an azeotropic mixture of dichloromethane (DCM) and methanol (93:7) in Soxhlet apparatus for 72 h. Extracts and oils were deasphalted and then fractionated into saturated hydrocarbons, aromatic hydrocarbons and NSO compounds by open-column liquid chromatography on silica gel/ alumina, eluting successively with petroleum ether, petroleum ether/DCM (40:60) and DCM/methanol (35:65). Saturated hydrocarbons were further separated into n-alkanes (silicalite-adduct; SA) and branched-cyclic hydrocarbons (silicalite non-adduct; SNA) using silicalite powder (West et al., 1990). Gas chromatography (GC) was carried out on the SA fractions of both the extracts and the kerogen pyrolysates. A Varian 3400 gas chromatograph fitted with an OV101 fused silica column ( 2 5 m x 0 . 2 5 m m i.d.) was used. The oven was programmed from 60 to 300°C at 4°C/min and held at the final temperature until all compounds had eluted. Hydrogen was used as the carrier gas. The SNA fractions were analysed in the multiple reaction monitoring (MRM) mode using a VG Analytical AutoSpec-UltimaQ mass spectrometer fitted with a Carlo Erba 8060 gas chromatograph

716

K h a l e d R. A l - A r o u r i et al.

and an A200S Autosampler, and controlled by a VG OPUS data system. The gas chromatograph was equipped with a 50 m x 0.2 mm i.d. HP Ultra-1 crosslinked methylsilicone capillary column. Samples (in hexane) were injected (splitless mode for 1 min) at 28°C. The oven was held at 50°C for 2 min before its temperature was raised to 150°C at 15°C/min, then to 310°C at 3°C/min, and held isothermal for 28 min. The carrier gas was hydrogen. Ions were generated by electron impact with an accelerating voltage of 8 kV. The total analysis time was 90 min with a cycle time of 1.82 s. Kerogen concentrates were obtained from six representative samples of the Snake Creek Mudstone. Solvent-extracted rock powder was exhaustively macerated with hydrochloric and hydrofluoric acid to remove the mineral matter. This was followed by centrifugation and/or flotation in DCM to concentrate the kerogen. Sealed-tube hydrous pyrolysis of the kerogen concentrate (~50mg) was carried out according to the procedure of Boreham and Powell (1991). The pyrolysates were fractionated into saturated hydrocarbons, aromatic hydrocarbons and NSO compounds in the same manner as the extracts. Saturates were further separated into SA and SNA fractions. The oil and extract fractions (i.e. saturated hydrocarbons, aromatic hydrocarbons, and NSO compounds), kerogen concentrates and kerogen pyrolysate fractions (saturates and aromatics) were analysed for their stable carbon isotopic composition. Samples (2mg) were sealed with copper oxide in evacuated quartz tubes and heated at 950°C. The resulting CO2 was analysed in a Europa Scientific isotope-ratio mass spectrometer. Results are expressed as per mil relative to the PeeDee Belemnite (PDB) standard. RESULTS AND DISCUSSION

Source richness, kerogen type and maturity Back Creek Group. Early Permian mudstones of the Back Creek Group, examined in four wells (Cockatoo Creek-l, Burunga-1, Meeleebee-1 in the northern part of the study area, and Flinton-1 in the south), have fair to very good organic richness (TOC = 0.7-4%) but a poor hydrocarbon yield ( < 500 ppm) and, at best, are only a fair oil source (Fig. 2a). The Back Creek Group contains essentially gas-prone Type III/IV kerogen (Fig. 2e) which is mature in the south (Ro=0.87%) and generally overmature in the north (Tmax=460-505°C, Ro = 1.5-2.3%). These high maturation levels have obscured the original maceral composition, and resulted in n-alkane distributions maximising in the lower molecular weight range. Therefore, all its liptinites will have been converted to rank-micrinite (Fig. 3b). Low hydrogen index values (HI = 3-44,

Fig. 2e), poor genetic potential (S1 + $2 < 2 k g hydrocarbons/tonne), minimal extractable C15 + hydrocarbon yields (2-11 mg/g TOC) and low pristane/n-heptadecane (<0.6) and phytane/n-octadecane (_<0.2) values are all consistent with overmature organic matter of low reactivity. These data imply that the bulk of the Back Creek section is within the gas window; and that liquid hydrocarbons were capable of being generated from its kerogen and have already been expelled from these rocks. At Scotia-l, just north of Burunga-1 (Fig. lb), gas is bleeding from the Gyranda Formation, whereas oil traces were observed in fi'actures within tuffaceous sandstone of the Back Creek Group, and in fractured basement. A marine influence in the lower part of the Back Creek section is indicated by a residual even-carbon-number predominance at Ci6, Cjs and C20 in its n-alkanes and by pristane/phytane values < 1 (e.g. sample from Cockatoo Creek-1 in Fig. 5). Blackwater Group. Late Permian coals and carbonaceous shales of the Blackwater Group have TOC and Cis~ hydrocarbon contents characteristic of fair to good oil-source rocks (Fig. 2b). Their genetic potential (SI + $2 = 12-193 kg hydrocarbons/ tonne) and hydrogen index values (HI = 120 290, Fig. 2e) reveal the presence of better quality Type I1/1II kerogen with some ability to generate oil and gas. Maturity ranges from initially mature in the south of the study area (Tm,,x=431-443°C; P I - 0.08-0.12) and along the flanks of the Taroom Trough to within the oil window at Burunga-1 (T,..... = 4 4 4 461"C; PI = 0.20 0.25). Further north at Glenhaughton-1 this unit has entered the wet gas window (Ro = 1.6%, Thomas et al., 1982; Hawkins et al., 1992). These source rocks contain abundant liptinite (mainly cutinite, resinite, liptodetrinite and rare sporinite) in which fluorescence is subdued, probably due to expulsion of much of their hydrocarbons (Fig. 3c). Snake Creek Muds'tone. With the exception of siltstone intervals in three wells (TOC_< 0.7%), all 41 samples of this Middle Triassic lacustrine unit have good to very good organic richness (TOC = 1-4%) and hydrocarbon contents indicative of a fair to very good source for oil (Fig. 2c). It contains initially mature (T,..... =429 440°C) Type Ill or Type ll/IIl kerogen (Fig. 2f) with a fair to good petroleum potential (Sl + $2 = 4 6 kg hydrocarbons/tonne). Vitrinite reflectance measurements indicate that this unit has passed the generation threshold for Type III kerogen (Ro=0.7%) over the axial part of the trough, with the highest reflectance recorded at Inglestone-1 (Fig. 4a). This maximum maturation level corresponds to the early mature stage of hydrocarbon generation for Type II/III kerogen. A hydrogen index-contour map for the Snake Creek Mudstone in the southern Taroom Trough (Fig. 4b) shows t h a t its highest hydro-

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carbon-generating potential (HI > 200) is developed in the southwestern part of the trough in the vicinity of Borah Creek-3 and -4, Tinker-2, Inglestone-1 and Flinton-1 (see also Smyth and Mastalerz, 1991). Outside this "sweet spot" the Snake Creek Mudstone has hydrogen indices in the range HI = 39-182. Petrographic examination revealed that those samples with the highest hydrogen indices contain liptinite-rich dispersed organic matter which bears a close resemblance to Type II kerogen. The abundant liptinite comprises mainly lamalginite (Fig. 3d), cutinite and liptodetrinite, with rare to common sporinite and resinite (Fig, 3e). Dinoflagellares, acritarchs and Botryococcus-like algae are occasionally recognisable within a highly fluorescing groundmass (A1-Arouri, 1996). Jurassic units. Coals and carbonaceous mudstones from various Jurassic units (Evergreen Formation, Precipice Sandstone, and Walloon Coal Measures) were shown to have fair oil potentials (Fig. 2d). However, they are immature (Tm~,x -< 430°C) throughout the Surat Basin (Fig. 2f; see also Thomas et al., 1982) and therefore cannot be effective source rocks for any of its oils. Petrographic evidence (~ic oil generation in the Snake Creek Mudstone Given its kerogen type and observed maturation levels (Fig. 4), the Snake Creek Mudstone may be expected to be actively generating petroleum within a relatively small area of the southern Taroom Trough. Certainly, some of its liptinites and perhydrous vitrinites have passed their nominal oil generation thresholds (Ro = 0.45% for certain kinds of resinite, 0.5% for desmocollinite and bituminite, and 0.6% for sporinite and cutinite: Cook, 1982; Teichmfiller and Durand, 1983). Even at this low maturity level, kerogen rich in such thermally labile macerals can generate significant amounts of light oil and condensate (Snowdon and Powell, 1982). Microscopic observations (e.g. Fig. 3f) confirm that hydrocarbon generation from the Snake Creek organic matter has indeed started, with the best generating potential developed on the southwestern edge of the trough. This is indicated by intense yellowfluorescing liptinites and brown-fluorescing desmocollinite and telocollinite, with many phytoclasts apparently expelling their hydrocarbons into the surrounding medium. Vitrinite fluoresces when it is hydrogen-rich, indicating good oil-generating abil-

ity. Alternatively, vitrinite may fluoresce when its micropores are impregnated by liquid hydrocarbons generated from associated liptinites (Mukhopadhyay and Hatcher, 1994). Extensive micrinitisation in a few sample s m a y indicate previous hydrocarbon generation (Stach et al., 1982). Exsudatinite and/or oil is present in telocollinite fractures and fusinite cell lumens (Fig. 3f). In many samples, fluorinite is seen dissolving in the mounting medium to form oil haze. Oil haze surrounds cutinite, resinite, fluorinite and alginite, whereas oil droplets (live oil!) have mobilised and migrated into the surrounding rock matrix. Petroleum geochemistry Data on the bulk chemical and isotopic composition of the oils are presented in Table 1. Source and maturity-dependent biomarker parameters of the oils and source rocks are summarised in Table 2. Alkane chromatograms representative of two different oil signatures are shown in Fig. 5. Alkane profiles of representative Permian, Triassic and Jurassic source rocks are also displayed for comparison. Selected maturity-dependent and source-specific biomarker ratios, based on both saturated and aromatic hydrocarbons, are plotted in Fig. 6. Expulsion maturity. As estimated from their biomarker isomer ratios (C31 hopane 22S = 57-64%; C3o fl~/~fl hopane < 0.14; T~/Tm =0.40-1.32; C29 sterane 20S = 55-62%: Table 2; Fig. 6a) and calculated vitrinite reflectance derived from methylphenanthrene index (MPI, Radke and Welte, 1983) measurements (Table 1), most of the oils were expelled from their source rocks early in the conventional oil-condensate window, and at reasonably similar maturity levels (Re = 0.62-0.75%). The Rednook-1 crude appears to be a somewhat later expulsion product (Rc=l.04%), consistent with its description as a condensate. With this one exception, the calculated vitrinite reflectance values obtained here are within the range reported by Boreham (1995) for a larger set of Bowen/Surat oils. Oil Jamilies. Two different families of crude oils can be recognised. Those assigned to Family 1 are the very light (65c'APi) petroleums from Roswin North-I and Rednook-l, both reservoired in the Triassic Showgrounds Sandstone. Each has a nonwaxy, unimodal n-alkane profile (maximum around n-tridecane, Fig. 5), although their respective pris-

Fig. 3. Photomicrographs of dispersed organic matter. Plates a and b (incident white light): texto-ulminite and sporinite, intensely micrinitised and extensively pyritised, in the Back Creek Group, Cockatoo Creek-1 (x625). Plate c (fluorescence mode): phytoplankton and lamalginite in Back Creek Group, Burunga-1 (×1563). Plate d (fluorescence mode): dull-fluorescing resinite in carbonaceous shale facies of the Blackwater Group, Burunga-I (×625). Plate e (fluorescence mode): lamalginite (la) associated with pyrite framboid (py) in Snake Creek Mudstone, Muggleton-1 (x625). Plate f (fluorescence mode): resinite (r), sporinite (sp) and cutinite in Snake Creek Mudstone, McGregor-1 (×625). Plate g (white light): exsudatinite (dark grey) filling cell cavities of fusinite in the Snake Creek Mudstone, Tiggrigie Creek-1 (×1563). Plate h (fluorescence mode): same field of view as (g).

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tane/phytane ratios are quite different (pr/ph = 5.6 and 1.7). This latter discrepancy may be largely due to differences in maturity at the time of primary migration. Most importantly, the carbon isotopic compositions of their saturated and aromatic hydrocarbon fractions are relatively light (613C~ - 27%0, Table 1). The remaining oils in Table 1 all belong to F a m i l y 2. Most are of lower API gravity (40-47 °) than the minor Family l crudes, and have n-alkane distributions similar to that of the Cogoon River West-1 oil (Fig. 5). Their pristane/phytane ratios are uniformly high (pr/ph = 4 6). Although their reservoir formations differ, ranging in age from Permian to Jurassic, all unaltered Family 2 oils are relatively waxy (Hawkins et al., 1992; Boreham, 1995). The Riverslea-1 oil (not shown in Fig. 5) is clearly biodegraded, as indicated by its lack of n-alkanes and isoprenoids. Nevertheless, its polycyclic biomarkers and carbon isotopic composition (613C~-24%0, Table 1) prove its close relationship to the Family 2 oils, which appear to possess a characteristically heavy isotopic signature (see next section). Oils from both families are characterised by high saturated/aromatic hydrocarbon ratios (sat/ arom = 3 23, Table 1) together with high pristane/ phytane ratios (pr/ph = 4-6), typical of oils derived from vascular plant remains deposited in a predominantly oxic environment (Powell and McKirdy, 1973; Clayton, 1994). The terrestrial nature of the oils is reflected also in their sterane distributions (C29>C28~__C27 steranes: Table 2; Fig. 6b and c), and moderate to high hopane/sterane ratios (hop/ster = 1.2 7). Lower values for the latter ratio ( h o p / s t e r - 0.6 0.7) in the Wilga-2 (Fig. 7a) and Washpool-1 oils are attributed to preferential biodegradation of hopanes. Although steranes are known to undergo biodegradation before hopanes, the reverse does also occur; and where this has happened (as in the case of these two oils) the affected hopanes are converted to 25norhopanes (Peters and Moldowan, 1993). Thus, in situ bacterial alteration of these oils has enhanced the relative abundances of the more resistant hopanoid compounds (viz. 25-norhopanes, 18c~(H)-30norneohopane and methylhopanes), whereas the steranes appear to be unaffected. The absence of the marine algal biomarker, 24-n-propylcholestane, from all the oils examined further emphasises their terrestrial origin. The oils exhibit moderate to high abundances of diasteranes relative to steranes (C29 dia/ster = 1-2, Fig. 7). This compositional feature is associated with high relative concentrations of diahopane (C3o diah/hop = 0.1 0.6) and 18e(H)-30-norneohopane (C29Ts/30-NH = 0.1 0.4: Table 2, Fig. 7)indicating deposition of their precursor terrestrial organic matter in a clay-rich, oxic suboxic environment (Peters

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Petroleum systems of the southern Taroom Trough, Australia and Moldowan, 1993). The inferred argillaceous character of the source rocks is consistent with the low 30-norhopane/hopane ratios (< 1) of the oils; and with their lack, or very low concentration, of 29,30-bisnorhopane (cf. Clark and Philp, 1989). Other specific bacterial biomarkers (including 2eand 3/~-methyl-17e(H)-hopanes; 28,30- and 29,30bisnorhopanes; and 2e- and 3/~-methylsteranes, Peters and Moldowan, 1993) occur ubiquitously in all the Permo-Triassic oils and sediments analysed and, therefore, are of no help in distinguishing the two oil families. However, differences in their respective distributions of bicyclic sesquiterpanes and 4e-methylsteranes do allow for molecular discrimination between the oils of Families 1 and 2 (see next section).

Oil-source rock correlation Triassic oils (Family 1). A positive correlation exists between the C14 16+ bicyclic alkane distributions of the Family 1 oils (represented by the Roswin North-1 crude) and shales of the Snake Creek Mudstone. Both oils and source rocks have abundant Ct4 15 rearranged and regular bicyclic alkanes while C16+ homologues are nearly absent (Fig. 8). These oils are also characterised by the near absence of tricyclic terpanes (including C30), again resembling the Snake Creek extracts (A1Arouri et al., 1995). This may imply generation from a less mature source rock (cf. Peters and Moldowan, 1993) and/or an entirely different organic facies (cf. Seifert and Moldowan, 1978). The later explanation is favoured here since the oils in this family appear to have been generated at different maturity levels (Table 1). Although the Roswin North-1 oil has a distinctive sterane distribution (C27>>C28, Fig. 7), the Family 1 oils cannot be distinguished from those of Family 2 on the sterane ternary plot (Fig. 6c). Interestingly, however, the two oil families exhibit quite different relative concentrations of C30 methyl steranes, with the highest abundances being found in the Family 1 oils (Fig. 6c). This may be another, albeit subtle, indication of a common source for Family 1 oils. Also, the Triassic oils have markedly higher abundances of 4a-methylsteranes, including tentatively identified dinosterane (4c~S/3flS ~ 1; dino/3/~S ~ 0.1-0.2: Fig. 9). Elevated abundances of 4c~-methylsteranes are observed in many Snake Creek Mudstone extracts (Fig. 9), providing further testimony to the origin of the Family 1 oils from this Triassic unit. The presence of dinosterane is consistent with other evidence of marine incursions to the Snake Creek palaeolake along the northwest and southeast margins of the southern Taroom Trough (e.g. acritarchs at Glenhaughton- 1, Tiggrigie Creek-l, Amoolee-1 and Cabawin-l: A1Arouri, 1996).

727

Permian oils (Family 2). The oils of this family (e.g. Bellbird-1, Fig. 8) are likewise enriched in C14 15 bicyclic alkanes, including rearranged drimanes, at the expense of their C~6+ homologues, with the later being either absent or present as minor components, consistent with their origin from coal and/or shale source rocks (cf. Palacas et al., 1984; Noble et al., 1986). Variations in the drimane distributions of different Permo-Triassic lithofacies suggest that abundant homodrimanes and methylhomodrimanes are a characteristic feature of calcareous mudstones deposited under less oxic, and probably more saline, conditions (A1Arouri et al., 1995). The absence of this class of sesquiterpanes in the present suite of Taroom Trough oils and condensates precludes the calcareous facies from being their source (Fig. 8). The tricyclic terpane distributions of these oils can be used as evidence for their generation from the carbonaceous facies of the Blackwater Group. Both contain abundant C~9 and C20 cheilanthanes which predominate over their C21 and C23 homologues and C30 hopane, attesting to their derivation largely from higher plant precursors which were deposited in a predominantly oxic environment (Peters and Moldowan, 1993; AI-Arouri et al., 1995). In the calcareous mudstones of the Back Creek Group the reverse relationship occurs (C21 and C23>>CI9and C20 cheilanthanes). On the basis of the relative abundances of C27, C28 and C29 steranes (Fig. 6c), the Blackwater shales appear to be poorly correlated to any of the Family 2 oils. However, enhanced relative abundances of the lower-molecular-weight steranes in the oils may be due to fractionation during migration of the oil. Alternatively, the effective source rocks may be more mature equivalents of the Blackwater carbonaceous shales analysed in this study. The latter explanation is favoured since a shift to lower homologues is known to be maturityrelated (e.g. Curiale, 1992). High concentrations of 2~- and 3fl-methylsteranes relative to their 4amethyl isomers is another feature that characterises most of the oils and Permian sediments in the Bowen/Surat Basin. All the Permian oils have low relative abundances of 4~-methylsteranes (4~S/ 3 f l S ~ 0.3), and are devoid of dinosterane (Fig. 9). Similar methylsterane distributions are found in the carbonaceous shales of the Late Permian section. Two of the Family 2 oils show minor, but significant, departures from this Permian methylsterane pattern. The Taylor-12A oil exhibits a somewhat higher concentration of 4c~-methylsteranes than the other Permian oils (parameter 27, Table 2); and the Merroombile-1 condensate contains a trace amount of dinosterane (parameter 30, Table 2). Thus, these two petroleum accumulations appear to have received a small proportion of their hydrocarbon charge from the Triassic source kitchen.

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Petroleum systems of the southern Taroom Trough, Australia Aromatic source parameters. The methylphenanthrene and trimethylnaphthalene distributions of selected oils from both families are consistent with the inferred pre-Jurassic age of their respective source rocks. In the two aromatic source affinity diagrams devised by Alexander et al. (1988) to distinguish oils of Jurassic and Permian origin in the Cooper/Eromanga Basin, the Taroom Trough crudes plot in (or immediately adjacent to) the lower left quadrant (Fig. 6e and f). Note that, in terms of its aromatic hydrocarbon signature, the Triassic Family 1 oil from Roswin North-1 oil (sample 4) is indistinguishable from the Permian Family 2 oils. Stable carbon isotopic composition. Assuming the aromatic fraction to be representative of the whole oil (Schoell, 1984), eleven out of thirteen oils have very similar 613C values, averaging -24.3%o (range -25.0 to -23.6%0, Table 1). The Roswin North-1 oil (~13C=-26.8%0) and Rednook-1 condensate (613C = -27.4%o), by way of contrast, bear distinctly light isotopic signatures which clearly differentiate them from the other (Permian) oils (Fig. 10). It is worth noting that the aforementioned Triassic contribution to the Taylor-12A and Merroombile-1 petroleums is insufficient to affect their isotopic signatures which therefore remain heavy. Genetic relationships between oils and their sources can be demonstrated using a Stahl (1978) plot, a pristane/phytane ratio versus 6~3C plot, and a Sofer (1984) plot (Fig. 10a-c). These diagrams indicate that the Permian oils are genetically related and best match the Permian source rock kerogens (613C = - 2 4 . 6 to -22.9%0) and extracts. The Triassic oils plot separately and can be tied to a Triassic source (Snake Creek Mudstone: kerogen ~ 1 3 C = - 2 8 to -26%0). The combined effects of maturity (cf. Simoneit et al., 1981) and organic facies (cf. Lewan, 1986) differences best explain the observed variations in 613C values for the Triassic and Permian facies. It is interesting that 13C-depletion of this magnitude appears to be an Australia-wide feature of Triassic marine settings (Summons et al., 1995). Normally, oils show 6~3C variations of up to 1.5%0 relative to their source rock bitumens (Peters and Moldowan, 1993) or kerogens of similar maturity. In fact, this is what is observed here for both the Permian and Triassic oils when compared with their respective Permian and Triassic extracts, kerogens and kerogen pyrolysates (Fig. 10). The aromatic fractions of the oils clearly obey this 1.5%omaximum-difference rule when compared to the aromatics of their source rock bitumen. The kerogen and extract saturates fractions of a coal from the Jurassic Walloon Coal Measures have carbon isotopic compositions falling within the range for Permian oils and source rocks (Fig. 10c). However, the possibility of the Walloon being a

731

source for these oils is precluded on the basis of its immaturity (Fig. 21); and by the lack of enhanced concentrations of the characteristic Araucariacean conifer resin biomarkers (viz. 1,2,5-trimethylnaphthalene, 1-methylphenanthrene, 1,7-dimethylphenanthrene and retene, Fig. 6e and f) in any of the oils. Recognition o f petroleum systems A petroleum system starts when a source rock generates hydrocarbons (Magoon, 1992). Thus, the presence of hydrocarbons is proof of a petroleum system, the essential elements of which are the source, reservoir, seal and overburden rocks (Magoon and Dow, 1994). Petroleum systems can be classified according to the kerogen type or the age of their source rock (Magoon, 1992). Identification of two oil families within the set of oils analysed necessitates the existence of (at least) two distinct petroleum systems in the Taroom Trough. Triassic petroleum system. This system involves Triassic source and reservoir rocks in a very localised area of the southwestern part of the trough. It encompasses the Roswin North and Rednook petroleum pools (as well as part of the Merroombile and Taylor accumulations), all reservoired in the Showgrounds Sandstone, and the Snake Creek Mudstone source rock in the vicinity of Borah Creek-3 and 4, Tinker-2, Inglestone-I and the adjacent deeper parts of the trough. This system can, therefore, also be called the "Snake Creek-Showgrounds petroleum system" (A1-Arouri et al., 1998). Its lateral extent is, most likely, confined to the area of the best hydrocarbon generating potential as outlined in Fig. 4b. Here, the Snake Creek source rocks have attained an appropriate thermal maturity for (and display petrographic evidence of) active hydrocarbon generation, as discussed previously. Where juxtaposed with carrier and reservoir rocks, this source rock unit has contributed to the oil found in the underlying Showgrounds Sandstone. The measured maturity of the Rednook condensate (Rc = 1.04%) suggests that the Snake Creek Mudstone has, in fact, attained somewhat higher maturation levels than indicated in Fig. 4a. These more mature areas of the Snake Creek kitchen most likely occur along the axis of the Taroom Trough where no drillholes have yet penetrated the unit. The limited area (Fig. 4) and average thickness (19 m) of mature source rock is consistent with the relatively minor amounts of hydrocarbons discovered in this petroleum system (6.1 x 104 m 3 oil, 4.6 × 104 m 3 gas: AI-Arouri et al., 1998). Permian petroleum system. This system, unlike the Triassic system, is of wide areal and stratigraphic extent. It includes the source rocks of the Blackwater Group, which are mature to overmature throughout much of the Taroom Trough, and all

732

Khaled R. A1-Arouri et al.

Family 2 oils and related hydrocarbons produced from reservoirs of Permian to Jurassic age along the southeastern and southwestern margins of the trough (AI-Arouri et al., 1998). This geochemical study has proven that oils in this system are derived mainly from carbonaceous shales of the Blackwater Group. Most of the oil in this system is reservoired in the Precipice Sandstone' (Fig. lc). Hence, this system can conveniently be called the "Blackwater-Precipice petroleum system". Its discovered reserves are 7.2x 106m 3 oil and 1.4x 101°m 3 gas (A1Arouri et al., 1998). Thermal maturation and petroleum generation in both systems, as simulated kinetically (A1-Arouri et al., 1998), suggests that generation of hydrocarbons in the Permian-sourced petroleum system started at about 175 Ma and ended at 90Ma, whereas the Snake Creek Mudstone commenced charging its Triassic reservoir about 50 Ma later (125-75 Ma). In the north, the bulk of the generated hydrocarbons were expelled well before the main deformation event (Late Triassic-Jurassic), whereas, in the south, generation post-dated the development of trap structures, making the southern regions more prospective for hydrocarbons.

CONCLUSIONS The major potential source rocks in the Taroom Trough are marine mudstones in the lower part of the Permian section (Back Creek Group), and coals and carbonaceous shales in its upper part (Blackwater Group). Both the marine and nonmarine lithofacies are organic-rich and have attained sufficient maturity for oil and gas generation. However, using terpane and sterane biomarkers and isotopic data, the major source of the trough's oil was shown to be the Late Permian Blackwater Group. These isotopically heavy oils (613Carom~-24%o) occur widely throughout the study area, mostly in the Precipice Sandstone but also in other reservoirs of Permian to Jurassic age. They are therefore assigned to the "BlackwaterPrecipice" petroleum system. In addition, a previously unrecognised subsidiary oil source was identified, the Middle Triassic lacustrine Snake Creek Mudstone. This moderately organic-rich unit was deposited in a largely suboxic freshwater setting. It exhibits its best generating potential (good quality Type II/III kerogen of appropriate thermal maturity) in a very localised area between Tinker-l, Inglestone-1 and Flinton-1, and in the adjacent deeper parts of the southwestern trough. This unit has sourced the isotopically lighter oils ( 6 1 3 C a r o m ~ - 27%o) in the Roswin North and Rednook fields (and also contributed to the Taylor and Merroombile accumulations), all of which are produced from the Showgrounds Sandstone. These new Triassic oil-source corre-

lations demonstrate the existence of a second system, the "Snake Creek-Showgrounds" petroleum system in the southern Taroom Trough.

Acknowledgements--This research forms part of a Ph.D. study by the senior author who gratefully acknowledges financial support from an Overseas Postgraduate Research Award and a University of Adelaide Postgraduate Research Scholarship. Technical assistance was provided by Zarko Roksandic, Janet Hope, Zoltan Horvath and Andrew Murray (Australian Geological Survey Organisation, AGSO). We also thank Peter Green (Geological Survey of Queensland) for source rock samples and well data. Crude oil samples were supplied by Bridge Petroleum Ltd., Command Petroleum Holdings N.L. and Oil Company of Australia N.L. The paper benefitted from thoughtful reviews by Dr Akihiko Okui and Dr Gerard Lijmbach. CJB publishes with the permission of the Director, AGSO. REFERENCES

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APPENDIX

Key To Biomarker Parameters Listed In Table 2 Parameter

Maturity-dependent parameters 1 %22S 2 3 4

Mor/Hop T~/Tm %20S

Source-specific parameters: hopanes 6 25NH/Hop 7 30NH/Hop 8 29,30BNH/Hop 9 28,30BNH/Hop 10 2 + 3MeH/Hop 11 2MeH/3MeH 12 C~9T~/30NH 13 C30 Dia/Hop 14 Hop/Ster

Derivation

%22S/(22S + 22R)-C3t homohopane = 100 x 17c~(H),21/J(H) 22S homohopane/17:~(H),21/?(H) 22(S + R) homohopane C30 moretane/C30 hopane - 17[3(H),21~(H)-hopane/17c~(H),21/~(H)-hopane C27 18ct(H)-22,29,30-trisnorneohopane/C~7 17~(H)-22,29,30-trisnorhopane % 20S/(20S + 20R)-C29 sterane - 100 x 5cffH), 14c~(H),17:~(H)-24-ethylcholestane 20S/ 5~(H),14(H)~,17~(H)-24-ethylcholestane 20(S + R) %[~[3/(tq[~ + 7c0-C29 sterane = 5:~(H),14/~(H),17/~(H)-24-ethylcholestane 20(S + R)/ [5~(H),14/~'(H),17/qH)-24-ethylcholestane 20(S + R) + 5~(H),14c~(H),17~(H)-24-ethylcholestane 20(S + R)]

C29 17~(H),21/J(H)-25-norhopane/C30 17c~(H),21/~'(H)-hopane C29 177(H),21fl(H)-30-norhopane/C3o 17a(H),21//(H)-hopane 29,30-bisnorhopane/C30 17a(H),21/i(H)-hopane 28,30-bisnorhopane/C3o 17~(H),21/J(H)-hopane C3t (2a + 3/$)-methylhopane/C3o 17:~(H),21/$(H)-hopane 2a-methylhopane/3//-methylhopane 18~(H),21fl(H)- 30-norneohopane/C 29 17a(H),21/~(H)-30-norhopane C30 17~(H)-diahopane/C3o 17~(H),21/~:(H)-hopane hopanes/steranes, where hopanes = I~C_~734 hopanes and moretanes - C27 trisnorhopanes (7',+ 7',11) + C2s bisnorhopanes (28,30-BNH + 29,30-BNH) + C29 (30-NH + 30normoretane) + C3o (hopane + moretane) + C3t 34 (homohopanes + homomoretanes); and steranes = 1~C27 2~ [5~(H),I4~(H),I7~(H)-20(S + R) + 5~(H)A4[I(H),I7[I(H)-20(S + R)] steranes

Source-spec(fic parameters: steranes and methyLs'terane.~ 15 C27:C28:C29 5~(H),14~(H),17~(H)-cholestane 20R: 5~(H),14~(H),17~(H)-24-methylcholestane 20R: 5c~(H),I4~(H), 17~(H t-24-ethylcholestane 20R 16 C30/C29 5~(H),t4~(H),17c~(H)-24-n-propylcholestane 20R/5~(H),14c~(H),17~,t(H)-24-ethylcholestane 20R 17 Dia/Ster 5c~(H),13/~'(H),17~(H)-dia-24-ethylcholestane 20(S + R)/[5~(H).14:~(H),17~(H)-24-ethylcholestane 20(S + R) + 5:~(H),14/~(H),17//(H)-24-ethylcholestane 20(S + R)] 18 C28 4-Methylsterane 100 × 4~-methyl-5c~(H),14c~(H),17~(H)-cholestane 20R/EC28 3. 4:~-methylsteranes 19 C29 4-Methylsterane 100 x 4c~-methyl-5:~(H),14c~(H),17~(H)-24-methylcholestane 20R/ZC2s 30 4:~-methylsteranes 20 C30 4-Methylsterane 100 x [4~-methyl-5~(H),14~(H),17~(H)-24-ethylcholestane 20R + 4ct,23,24-trimethyl5:~(H), 14~(H),I 7c~(H)-cholestane 20R]/ZC28 30 4~-methylsteranes 21 4Mest/Ster 4~-methyl-5~(H)A4~(H),17~(H)-24-ethylcholestane 20R + 4~,23,24-trimethyl-5c~(H),14~(H),17c~(H)cholestane 20R/5~(H),14c~(H),I 7c~(H)-24-ethylcholestane 20R 22 2 + 3Mest/Ster (2c~ + 3/t)-methyl-5~(H),14c~(H),17~(H)-24-ethylcholestane 20R/5~(H),14ct(H),17~(H)-24ethylcholestane 20R 23 4~S/313S 4~-methyl-5c~(H), 14~(H),I 7~(H)-24-ethylcholestane 20S/3[:t-methyl-5~(H),14c~(H),17c~(H)-24ethylcholestane 20S 24 Dino/3flS 4c~,23R.24S-trimethyl-5c~(H), 14c~(H),17:~(H)-cholestane 20R/3[4-methyl-5~(H),14~(H),17a(H)-24ethylcholestane 20S