A NEW PERSPECTIVE ON EXPLORING THE COOPER/ERO- MANGA PETROLEUM PROVINCE EVIDENCE OF OIL CHARGING FROM THE WARBURTON BASIN

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1 A NEW PERSPECTIVE ON EXPLORING THE COOPER/ERO- MANGA PETROLEUM PROVINCE EVIDENCE OF OIL CHARGING FROM THE WARBURTON BASIN C.O.E. Hallmann 1,4, K.R. Arouri,3, D.M. McKirdy and L. Schwark 1 Cologne Petroleum Group, Institute for Geology and Mineralogy, University of Cologne, Zuelpicher Strasse 49a, Cologne, Germany Organic Geochemistry in Basin Analysis Group, School of Earth and Environmental Sciences, University of Adelaide, SA 5005, Australia 3 Present address: Saudi Aramco R&D Centre, PO Box 158, Dhahran 31311, Saudi Arabia 4 Present address: Centre for Applied Organic Geochemistry, Curtin University of Technology, GPO Box U1987, Perth 6845, Western Australia Hallmann.C@gmx.net ABSTRACT The history of petroleum exploration in central Australia has been enlivened by vigorous debate about the source(s) of the oil and condensate found in the Cooper/Eromanga basin couplet. While early workers quickly recognized the source potential of thick Permian coal seams in the Patchawarra and Toolachee Formations, it took some time for the Jurassic Birkhead Formation and the Cretaceous Murta Formation to become accepted as effective source rocks. Although initially an exploration target, the Cambrian sediments of the underlying Warburton Basin subsequently were never seriously considered to have participated in the oil play, possibly due to a lack of subsurface information as a consequence of limited penetration by only a few widely spaced wells. Dismissal of the Warburton sequence as a source of hydrocarbons was based on its low generative potential as measured by total organic carbon (TOC) and Rock-Eval pyrolysis analyses. As most of the core samples analysed came from the upper part of the basin succession that has been subjected to severe weathering and oxidation, these results might not reflect the true nature of the Warburton Basin s source rocks. We analysed a suite of source rock extracts, DST oils and sequentially extracted reservoir bitumens from the Gidgealpa field for conventional hydrocarbon biomarkers as well as nitrogen-containing carbazoles. The resulting data show that organic facies is the main control on the distribution of alkylated carbazoles in source rock extracts, oils and sequentially extracted bitumens. The distribution pattern of alkylcarbazoles allows to distinguish between rocks of Jurassic, Permian and pre-permian age, thereby exceeding the specificity of hydrocarbon biomarkers. While no pre-permian signature can be found in the DST oils, it is present in sequentially extracted residual oils. However, the pre-permian molecular source signal is diluted beyond recognition during conventional extraction procedures. The bitumens that are characterised by a pre-permian geochemical signature derive from differing pore-filling oil pulses and exhibit calculated maturities of up to 1.6% R c, thereby proving for the first time the petroleum generative capability of source rocks in the Warburton Basin. KEYWORDS Warburton Basin, Cooper Basin, Eromanga Basin, carbazoles, secondary migration, sequential flow-through extraction, residual oils. INTRODUCTION The Cooper and Eromanga Basin couplet forms Australia s largest onshore petroleum province (Fig.1) and has been producing light oil and gas-condensate since the late 1960s. During the last several decades, there has been much debate concerning the sources of its oil and gas. Organic geochemical and petrographic studies (e.g. Taylor et al, 1988; Powell et al, 1991; Boreham and Hill, 1998; Michaelsen and McKirdy, 001; Kramer et al, 001; Michaelsen, 00) have shown that the Cooper Basin s Patchawarra Formation and, to a lesser extent, the Toolachee Formation, contain oil Figure 1. Map showing the location of the Jurassic-Cretaceous Eromanga Basin and the subjacent Permo-Triassic Cooper Basin. This couplet forms Australia s largest onshore petroleum province. The underlying Warburton Basin is of Early Palaeozoic age (from Hallmann, 004). APPEA Journal

2 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark and gas-prone coals and carbonaceous shales. Additionally, the Eromanga Basin hosts two significant oil-prone source units: the Birkhead and Murta Formations (Smyth et al, 1984; Michaelsen and McKirdy, 1989, 1996; Powell et al, 1989; Boult et al, 1998). A number of other stratigraphic units, such as the Epsilon and Poolawanna Formations, contain similar non-marine lithofacies capable of producing lesser amounts of petroleum, however, not in sufficient amounts to allow expulsion. The stratigraphic distribution of these multiple potential source rocks relative to the major reservoir units is illustrated in Figure. Initially regarded as an exploration target in its own right, the underlying Warburton Basin was subsequently considered not to have been a major contributor to the oil plays of the Cooper and Eromanga basins, although a Warburton source was considered for the Toby 1 oil from the southwestern Eromanga Basin based on isotopically light n-alkanes compared to the isotopicially heavier oils sourced from the Cooper and Eromanga basins (Boreham and Summons, 1999). The finding of liquid petroleum accumulations in the Early Cambrian Mooracoochie Volcanics at Sturt 6 and 7 in the southwestern Patchawarra Trough momentarily revived interest in the Palaeozoic strata that underlie the Cooper/Eromanga petroleum supersystem. However, isotopic and biomarker data obtained in a subsequent study (Kagya, 1997) reveal both oils to be of similar higher-plant source affinity and probably expelled from structurally lower Early Permian coals of the Patchawarra Formation in the overlying the Cooper Basin. When assessing the petroleum potential of the Warburton Basin two salient points cannot be ignored: the lack of outcrop and poor well penetration of its Cambro-Ordovician sedimentary sequence; and the highly oxidised state of its upper part (Boucher, 001). In contrast to other correlation studies that almost exclusively rely on the comparison of hydrocarbon signatures in oils and source rocks, we chose a reservoir geochemical approach, focussing on core extracts. Hereby, besides the conventional hydrocarbons, we placed special emphasis on the polar non-hydrocarbon fraction of bitumens. During the filling of an initially water-wet reservoir or carrier rock pore system by petroleum, the major part of the pore-water will be displaced by the oil. A thin layer of water will however remain, hydrating the pore walls. Among the most polar petroleum constituents are oxygen and nitrogen-containing compounds of low molecular weight (Larter et al, 000). These exhibit enhanced affinities to the hydrated mineral phase and will subsequently partition from the fluid petroleum phase of the reservoir towards the pore walls where they become immobilised and act as surfactants. Continuous progress of this mechanism results in an adsorbed oil layer of high polarity, which corresponds to the first oil charge, and effectively remains in position even when the non-adsorbed oil is displaced by subsequent oil charges that enter the pore system. This formation of a residual oil layer and the accompanying depolarisation of mineral walls results in a gradual change from a water-wet to an oil-wet system. We will henceforth refer to the aforementioned phases as free oil (displaceable and producible) and residual oil (adsorbed and non-producible). The free oil of a pore system thus corresponds to the last oil charge that entered a pore system and will be comparable to production and DST oils in terms of its molecular composition, while the residual oils form a cluster of layers that can be associated with previous oil charges (Schwark et al, 1997). SEQUENTIAL FLOW-THROUGH EXTRACTION Although the oldest residual oil layers carry valuable information on the characteristics of early oil charges, they typically consist of only one to 5% of the total bitumen only, and are diluted beyond detectability during conventional extraction procedures. In order to collect the molecular information encoded in discrete temporal phases of residual oil adsorption, we employed a flowthrough extraction method to recover the residual oil in a quasi-chronological order, the time increment represented by each recovered aliquot being determined by the minimum amount of bitumen that is needed for a sensible geochemical analysis (Schwark et al, 1997). Sequential flow through extraction (SFTE) is a non-destructive method, which allows recovery of discrete porefilling oil pulses from the intact pore system of a reservoir rock, following the first-in last-out principle (Schwark et al, 1997). Avoiding crushing and grinding samples prior to extraction prevents the generation of new mineral surfaces that can cause adsorption processes during extraction, leading to artificial fractionation, and consequently falsify the study of migration fractionation processes. The main benefit of this method is, however, the potential to separately extract free oil and discrete fractions of residual oils that are adsorbed as more or less discrete layers onto the mineral surfaces of pore walls (Figs 3 and 4 ). Leythaeuser et al (1988), Larter and Aplin (1995), and Stoddart et al (1995) noticed that core extracts contain a higher percentage of resins and asphaltenes than corresponding production oils from the same reservoir section. This is caused by selective adsorption of compounds onto mineral and/or organic phases during secondary migration, also termed geochromatography (Krooss et al, 1991). The passage of multiple petroleum pulses through a pore will result in a pseudo-layered system of adsorbed oils which reflects the continuous compositional change of the oil entering that part of the reservoir. During the first oil s dwell time in a pore space, polar compounds will experience interactions with the carrier rock mineral matrix and residual pore waters, resulting in a highly polar oil layer that is adsorbed onto the mineral surface of the pore wall. When a second oil charge displaces the free oil phase of the first charge, it will encounter less active sites on the pore walls as a residual oil layer from the first charge already covers these. Simultaneously the first oil charge will be forced into smaller pores. Adsorbed oil layer number two will thus generally be less polar than number one since the polar docking stations have been preconditioned. Thus the general state of the pore system gradually changes 6 APPEA Journal 006

3 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin Figure. Generalised stratigraphic column of the Warburton, Cooper, and Eromanga Basin sedimentary sequences, highlighting main source units and hydrocarbon reservoirs (from Hallmann, 004; modified after Michaelsen, 00 and Arouri et al, 004). APPEA Journal

4 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark Figure 3 (left). Diagram of SFTE apparatus (Schwark et al, 1997) showing sequential extraction of free oil and residual oils from an intact pore system following the first-in last-out principle (Hallmann, 004). Figure 4 (below left). Diagram showing the relationship between extract yield during SFTE, the gross composition of recovered fractions in terms of SARA (% saturates, aromatics, resins and asphaltenes) and the occurrence of free and adsorbed oil layers that may represent different charging events. Later extract fractions are characterised by increasing proportions of non-hydrocarbons. 64 APPEA Journal 006

5 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin from water-wet to oil-wet and the polarity of subsequent residual oil layers decreases. When a reservoir is charged by hydrocarbons from only one source rock, this should be reflected by laboratory extract yields of a decreasing maturity, controlled by the continuous filling of the pore system with oils from a progressively maturing source kitchen. The opposite is observed during continuous burial in a sedimentary basin; younger source rocks may reach the oil window and cosource into the same reservoirs as the older source rocks thus leading to lower maturity of the free-oil fraction (Leythaeuser et al, 000). In cases of in-reservoir mixing of oils from different sources, the charging history can be reconstructed by observing changes in facies-dependent markers. The free oil, corresponding to the last charge and yielded by the first extraction step, should possess characteristics similar to DST or production oils from the same reservoir section. Warburton Basin REGIONAL GEOLOGY Wopfner (1997) assigned Early Palaeozoic sediments that underlie the Permian deposits of the Cooper and Pedirka Basins to the Warburton Basin (Figs 1 and ). These were deposited in a continental shelf setting during the Cambrian and Ordovician, when the peri-equatorial position of Gondwana led to a sub-tropical climate. Due to poor well penetration little is known about lateral facies variations throughout the basin, or about the palaeodepositional environment. Common dolomitic and calcareous limestones, however, suggest a shallow marine setting that was dominated by evaporative processes. The organic geochemical signatures of Warburton Basin source rocks, which will be discussed later in this paper, also confirm this palaeo-environmental reconstruction. The thickest and possibly most important unit in terms of source rock potential is the Kalladeina Formation that represents the passage from several cycles of catch-up and keep-up carbonate sedimentation to a shelfal high stand system tract (Gatehouse, 1986). Erosion and severe oxidation of the Middle Cambrian to Early Ordovician sediments that were exposed as a palaeo-weathering surface resulted in a so-named altered zone that separates the pristine Warburton Basin succession from the overlying Cooper Basin sediments (Boucher, 001). Most wells that were drilled in the Cooper/Eromanga region end within the altered zone, thereby precluding a sensible evaluation of the Warburton source potential. A review of the previously available source rock data may be found in Roberts et al (1990). Cooper Basin The Late Carboniferous-Triassic Cooper Basin is a polyphase depocentre that began as a regional intracratonic sag, forming in response to deep mantle processes (Gravestock and Jensen-Schmidt, 1998) and lacking of any marine influence. Accumulation of sediments commenced after the Devonian-Mid Carboniferous Alice Springs Orogeny and ceased at the end of the Middle Triassic (Fig. ) as a consequence of basin-wide compression (Gravestock and Jensen-Schmidt, 1998). Folding and uplift led to a ridge and trough morphology that actively affected the sedimentation pattern (Alexander and Sansome, 1996). The Cooper Basin sedimentary sequence can be subdivided into the Early to Late Permian Gidgealpa Group, a lower series of non-marine deposits, and the latest Permian to Middle Triassic Nappamerri Group, which culminated in Triassic redbeds. The Gidgealpa Group is characterised by termino-glacial clastics, overlain by a detrital succession that includes low-sulphur humic coal measures. The coals occur mainly within the Patchawarra, Epsilon and Toolachee Formations, and attain their greatest thicknesses in the Patchawarra and Nappamerri Troughs. The Toolachee and Patchawarra coals are therefore considered as the principal Cooper Basin source units (Boreham and Hill, 1998; Boreham and Summons, 1999). The Tirrawarra Sandstone forms a reservoir unit of outstanding quality and hosts 80% of all Cooper Basin reservoired oils in the Tirrawarra field (Michaelsen, 00). Due to the Triassic coal gap no volumetrically significant source units can be found within the Nappamerri Group but its great lateral extent makes it a useful regional seal. Eromanga Basin The Jurassic-Cretaceous Eromanga Basin is an epicratonic sag basin that formed as a consequence of crustal subsidence in the Early Triassic (Alexander and Jensen- Schmidt, 1996). It entirely covers the Cooper Basin and most of the Warburton Basin (Fig. 1). The lower Eromanga Basin succession, represented by the Hutton and Namur Sandstones, was deposited by braided streams and displays excellent reservoir qualities. The Poolowanna Formation may be regarded as a silty and coaly facies of the Hutton Sandstone, and is an effective source rock in the southwestern Patchawarra Trough (Kagya, 1997). The Birkhead Formation represents a short-lived switch to a lacustrine coal swamp environment and is the Eromanga Basin s prime source unit (Smyth et al, 1984; Michaelsen and McKirdy, 1996). During the early Neocomian, a marine transgression allowed the deposition of Murta Formation lacustrine siltstones and shales, forming the third effective source rock unit in the Eromanga Basin (Michaelsen and McKirdy, 1989; Powell et al, 1989). Younger Eromanga strata will not be discussed due to their lack of adequate thermal maturity for hydrocarbon generation. Study area SAMPLING AND EXPERIMENTAL The Gidgealpa field, located on the southern end of the Gidgealpa-Merrimelia-Innamincka (GMI) Ridge was chosen to study petroleum migration and in-reservoir mixing, following on from the earlier work of Boult et al (1998) and Kramer et al (001). Its structure, a single draped an- APPEA Journal

6 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark ticline with four-way dip closure, comprises a northern and a southern culmination, which are separated by a shallow saddle (McIntyre et al, 1989). It is located on the crest of the Gidgealpa Ridge part of the GMI Ridge, an arcuate series of northeast southwest trending en echelon structures that form one of the three major structural trends in the Cooper Basin and separate the Nappamerri Trough from the Patchawarra Trough. Since most of the field s oil pools are situated there, this study focused on the southern Gidgealpa Dome (Fig. 5). The northern Gidgealpa Dome is the site of mostly gas pools in sands of the Toolachee and Patchawarra Formations (Figs 5 and 6). Sample preparation During the course of this study we analysed a suite of 4 drill stem test (DST) oils, 11 source rock extracts and 13 sandstone cores (Table 1). After extraction of the source rock samples with an azeotropic mixture of dichloromethane (DCM) and methanol (93:7) in a Soxhlet apparatus, both the source rock bitumens and the DST oils were fractionated into saturated hydrocarbons, aromatic hydrocarbons and maltene resins by medium pressure liquid chromatography (MPLC) using an automated MKW- MPLC device. Asphaltenes precipitated in n-hexane and were thus not recovered. For a more detailed description of this method the reader is referred to Radke et al (1980). SFTE Sandstone cores were brushed clean before a cm diameter plug was cut from the sidewall of the core. The 8 mm thick front and back ends of the newly won plugs were trimmed off and discarded. This was done to adapt core plugs to the size of SFTE cells and avoid contamination from drilling fluids on the outer core rims. The extraction was performed using dichloromethane (DCM) as the first solvent and a binary mixture of chloroform/methanol (1:1) as the second solvent. Extraction with the CHCl 3 /CH 3 OH started when colour was no longer observed in the DCM extracts. For a more detailed description of this procedure the reader is referred to Schwark et al (1997). Molecular analyses HYDROCARBONS The aliphatic and aromatic fractions were analysed by gas chromatography-mass spectrometry (GC-MS) in SIM mode using a HP 6890 GC interfaced to a HP MSD A HP-5 MS (crosslinked 5% phenylmethylsiloxane; 30 m long, 0.5 mm inner diameter, 0.5 μm film thickness) capillary column was used with helium as carrier gas. The oven temperature was held at 70 C for three minutes, then raised to 100 C at 6 C/min, to 00 C at 4 C/min, and finally to 310 C at 6 C/min at which it remained isothermal for 0 minutes. Data were acquired in both full-scan (m/z ) and selected-ion-monitoring (SIM) modes. For a more detailed description of the method see Hallmann et al (006). For calculation of the methylphenanthrene index (MPI: Radke and Welte, 1983), the phenanthrene peak area was multiplied by a response factor of RESINS The polar resin fraction was further separated using a two-step solid phase extraction (SPE) to obtain a fraction that is enriched in carbazoles (for details see Hallmann et al, 006). The carbazole fraction was further characterised by GC-MS (Fig. 7). A Hewlett Packard 6890 gas chromatograph was used interfaced to a Chromtech Kodiak 100 triple sector quadrupole mass spectrometer. The GC was equipped with a PVT injection system, operated in splitless mode, and a HP 5 fused silica capillary column (5% phenyl, 95% methylsilicone) of 30 m length, 0.5 mm inner diameter and 0.5 µm film thickness. The oven temperature was held at 60 C for two minutes, then programmed at 0 C/minute to 180 C, kept isothermal for one minute and programmed at 4 C/minute to 310 C and held at this final temperature for 10 minutes. Carbazoles were detected in selective ion monitoring (SIM) mode; monitored ions are shown in Figure 7. A more detailed description of the method can be found in Hallmann et al (006). Molecular parameters for facies, maturity and migration are shown in Table. RESULTS AND DISCUSSION Saturated hydrocarbon fractions from DST oils and source rock extracts were analysed by GC-MS to characterise their source-specific biomarker signatures and tentatively correlate the oils to their source rocks. Depositional environment Reconstruction of the environmental conditions prevailing during deposition and early diagenesis of the organic matter present in the studied rocks was achieved by evaluating acyclic isoprenoids and steranes (Peters and Moldowan, 1993; Killops and Killops, 1993). The acyclic isoprenoids pristane and phytane are derived primarily from the phytyl side chain that is cleaved from chlorophyll during diagenesis to form the unsaturated n-alcohol phytol (Didyk et al, 1978). The fate of phytol strongly depends on the redox state of the depositional environment and results in the preferential formation of pristane under oxic to suboxic conditions, and of phytane under anoxic depositional conditions (Didyk et al, 1978). Although tocopherol, which serves as an antioxidant in plants and algae, can be a source of pristane, and dihydrophytol, a phytane precursor, is present in Archaeal membrane lipids, their abundances are generally low and they do not influence the significance of the Pr/Ph signal (Peters and Moldowan, 1993, and references therein). The effect of thermal maturity on the Pr/Ph ratio is negligible. As might be expected for pre-ordovician sediments, the distribution of acyclic isoprenoids in the Warburton rocks analysed is skewed towards a predominance of phytane 66 APPEA Journal 006

7 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin Figure 5. A subsurface structural map of the Gidgealpa field showing the presence of two culminations. While the northern Gidgealpa Dome is dominated by gaseous hydrocarbon accumulations, most liquid petroleum is found in the southern Gidgealpa Dome. The red dotted line indicates the location of the cross section shown in Figure 8 (modified after McIntyre et al, 1989). APPEA Journal

8 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark oils have a slightly lower abundance of pristane relative to phytane. One reason could be heterogenous kerogen distributions in the source rock. While Cooper and Eromanga basin source rocks received an organic matter input of mainly higher-plant origin, Taylor et al (1988) suggested that sub-microscopic alginite, which is locally dispersed in the inertinite matrix of certain coals (notably those from the Patchawarra Formation), is the source of the Cooper oils. This may in part explain why some of the oils have lower pristane/phytane ratios and/or higher C 7 /C 9 sterane ratios than their inferred source rocks (Fig. 8). Powell et al (1991), however, rather argued for bacterial lipids as a source of Cooper Basin oils. ARAUCARIACAEAN MARKERS Figure 6. A schematic north south trending cross-section through the Gidgealpa field (see Fig. 7 for location) reveals the stratigraphic location of oil and gas pools (modified after Boreham and Summons, 1999). over pristane (Fig. 8), indicating that they were deposited under anoxic conditions. Cooper and Eromanga basin source units exhibit two- to four-fold excess of pristane over phytane, suggesting that their organic matter experienced oxic conditions during and shortly after deposition. This is consistent with the terrigenous nature of the Cooper and Eromanga sedimentary sequence. Steranes are important cell membrane-constituents of algae, fungi, and higher land plants (Patterson, 1994; Volkmann et al, 005). In general land plants are enriched in C 9 but depleted in C 7 steroids (Huang and Meinschein, 1979; Volkman et al, 005). The relative proportions of C 7 to C 9 desmethylsteranes exhibit evolutionary or age-diagnostic value (Grantham and Wakefield, 1988), with C 7 steranes predominantly derived from red algae (Rhodophyta) being abundant in sediments of early Paleozoic age (Schwark and Empt, 006). The humic kerogen that dominates the organic matter deposited in the Cooper and Eromanga basins contains a high relative abundance of C 9 steranes, which may preferentially originate from higher-plant derived phytosterenes. The three Warburton Basin rocks, on the other hand, are characterised by elevated amounts of C 7 steranes (Fig. 8), which is in accordance with a mixed input from diverse marine algae. Since Warburton Basin sediments predate the evolution of land plants few but algal sources of C 9 steroids existed. Oil-source rock correlation ISOPRENOIDS AND STERANES The distribution of steranes and the acyclic isoprenoids pristane and phytane in the DST oils shows that none of them carries a clear pre-permian molecular signature (Fig. 8). Compared to their corresponding source units, Alexander et al (1988) used aromatic biomarkers of the post-triassic conifer family Araucariacaea to distinguish between oils derived from the Permo-Triassic Cooper Basin and those derived from the overlying Jurassic-Cretaceous Eromanga Basin. While various Araucariacaean aromatic biomarkers including 1,,5-trimethylnaphthalene (agathalene), 1,7-dimethylphenanthrene, 1-methylphenanthrene and 1-methyl-7-isopropyl-phenanthrene (retene) are particularly abundant in Jurassic sediments and oils, they are virtually absent in pre-jurassic strata. In Araucariacaean conifers, the precursors of these molecules are found in leaves where they function as resin constituents (Wakeham et al, 1980). The ratios of 1-/9-methylphenanthrene (source dependent: Alexander et al, 1988) and -/1-methylphenanthrene (maturity dependent: Radke et al, 198) have proved useful in determining the extent of mixing between Cooper and Eromanga-sourced hydrocarbons. These ratios were first co-employed by Michaelsen and McKirdy (001) to document the widespread phenomenon of mixing of Permian and Jurassic oils in reservoirs across the Eromanga Basin. More recently Arouri et al (004) and Kramer et al (004) successfully applied them to Jurassic and Cretaceous oil pools in fields along the Murteree-Nappacoongee Trend using a recalibration of the original mixing model (Arouri and McKirdy, 005). While the aforementioned crossplots are perfectly capable of distinguishing Jurassic oils from pre-jurassic oils and have become an indispensable tool in geochemical studies of the Cooper/Eromanga basin region, further discrimination of non-jurassic oils hitherto has proved difficult. However, Boreham and Summons (1999) have used the carbon isotopic composition of individual n-alkanes to distinguish light Patchawarra-sourced oils from heavy Toolachee-sourced oils. Furthermore, a discrimination of Patchawarra- and Toolachee-derived oils is tentatively approached by considering the MPI-calculated thermal maturity of oils, assuming that Patchawarra oils have maturities in the range % R C, while Toolachee-derived oils are less mature within the range % R C. Michaelsen (00) further noted that the distribution of diahopanes may help distinguish Late Permian oils since the Toolachee Formation has a higher shale-to-coal ratio than the Patcha- 68 APPEA Journal 006

9 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin Table 1. Overview of samples from the Gidgealpa field that were used in this study. Sample Type Source Rock DST oil Well Depth Oil / extract DST1 DSTa DST3 DST4 DST6 DST1 DST1 DST DST1 DST4 DST7 DST DST1 DST3 DST6 DST7 DST DST3 DST6 DST1 DST3 DST4 DST6 DST1 Formation Toolachee Patchawarra Toolachee Patchawarra Tirrawarra Cambr.Dol. Toolachee Kalladeina Patchawarra Birkhead Birkhead Namur Namur Birkhead Hutton Patchawarra Patchawarra Birkhead Namur Hutton Poolowanna Patchawarra Birkhead Tirrawarra Toolachee Hutton Namur Hutton Poolowanna Hutton Poolowanna Epsilon Namur Namur Poolowanna Sample Type Cores Well Depth Oil / extract 4 a 3a 4 a a 4a 6a 3 a a 4a 4 1a+a 5 a 3a a a 4 a 3a a a 3a 4 a 5a Formation Toolachee Patchawarra Tirrawarra Nappameri/Toolachee Hutton Hutton Namur Birkhead Hutton Birkhead Hutton Hutton Tirrawarra warra Formation. The structures of rearranged hopanes are consistent with an origin via clay catalysed rearrangement of hopenes during early diagenesis (Moldowan et al, 1991). It is, however, difficult to predict lateral facies variations in these two coal-bearing units, and therefore the discrimination of Patchawarra-sourced and Toolacheesourced oils on the basis of the amount of diahopanes in analysed oils should be approached with caution. Carbazoles Nitrogen compounds in petroleum have been studied for many years (Snyder, 1965), largely because of their roles as health hazards, their involvement in catalyst poisoning, and their contribution to sludge formation in distillate products (Li et al, 1994). Charlesworth (1986) noticed that organically-bound nitrogen in kerogen pyrolysates is readily adsorbed by clay minerals, the activity of which correlates with their ion exchange capacity and the polarizability of the exchangeable cation. Yamamoto (1991) compared alkylbenzoquinolines in crude oils and source rock extracts and attributed the variation in abundance of nitrogen-shielded and nitrogen-exposed isomers to geochromatographic phenomena. During the 1990 s the petroleum research group at the University of Newcastleupon-Tyne extended this idea to the distribution of carbazoles (Fig. 7) in crude oils and source rock bitumens. Their high polarity, imparted by the nitrogen heteroatom, makes carbazoles sensitive to adsorptive interaction with clay minerals or solid organic matter by hydrogen bond- APPEA Journal

10 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark Figure 7. The elution order and chemical structure of some carbazole compounds. Exposed dimethylcarbazoles, trimethylcarbazoles and alkylbenzocarbazoles were not further examined in this study (modified from Hallmann, 004). 70 APPEA Journal 006

11 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin Table. Bio- and geomarker data of samples that were used in this study. Sample Type Well Depth Oil / extract Pr /Ph C7/C9 ster. 1-/9-MP MPI-1 1,7-/1,6-DMC BCR Source Rock DST oil DST DSTa DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST DST Cores x x x x a x x x 3a x x x x x x x a x x x x x x x x x x x x x x 0.45 a x x x a x x x a x x x x x x x a x x x x a x x x x 4a x x x x x x x a+a x x Continued next page. APPEA Journal

12 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark Continued from previous page. Sample Type Well Depth Oil / extract Pr /Ph C7/C9 ster. 1-/9-MP MPI-1 1,7-/1,6-DMC BCR x x x x x a x x x x 3a x x x x x x x x a x x x x x a x x x x x x x x a x x a x x x x x x a x x x x a x x a x x x x x x x x x x x a x x x a x x x ing. The initial results of this research suggested that the distribution of carbazoles in petroleum was controlled principally by fractionation processes during secondary migration (Li et al, 1994, 1995; Larter et al, 1996; Larter and Aplin, 1995; Schwark et al, 1997). However, it soon became evident that other factors such as maturity (Li et al, 1997; Clegg et al, 1998; Horsfield et al, 1998), source facies (Clegg et al, 1997; Bakr and Wilkes, 00; Hallmann, 004; Hallmann et al, 006; Schwark et al, 006) and biodegradation (Chunmin et al, 1999; Huang et al, 003) may also exert a strong control. Our knowledge of the origin of non-porphyrinic nitrogen compounds in the geosphere is limited (Li et al, 1995). The possible biological origins of carbazoles remain unclear but can tentatively be traced to alkaloids, proteins and pigments in terrestrial plants and algae (Snyder, 1965; Stankiewicz and van Bergen, 1997; Horsfield et al, 1998). ALKYLCARBAZOLES Figure 8. The distribution of steranes and acyclic isoprenoids in rock extracts and DSToils. The organic matter contained in rocks from the Warburton Basin accumulated under anoxic conditions (Pr/Ph <1) whereas that preserved in source rocks from the Cooper and Eromanga basins was exposed to oxygenated conditions during its deposition (Pr/Ph > ). Accordingly, the latter exhibit a marked predominance of C 9 over C 7 steranes, consistent with the derivation of their organic matter from higher plants. DST oils appear to derive from the Cooper/Eromanga source rock system. The distribution of alkylated carbazoles in petroleums has hitherto been studied in view of fractionation patterns, induced by differential shielding of the nitrogen by the alkyl groups (C1 and C alkylcarbazoles) and maturity controls (C1 carbazoles) since the methylcarbazole moiety has a significant similarity with the methyldibenzothiophene molecule. We found that in the Cooper/Eromanga Basin province, the distribution of alkylated carbazoles in oils, source rock extracts and sequentially extracted bitumens does not correlate with their measured thermal maturities. The distribution of -, 3-, and 4-methylcarbazoles in source rocks, however, is highly similar in rocks of the same stratigraphic age (Figs 9 and 10a), and allows the efficient discrimination of oils originating from pre-permian strata (Warburton Basin), the Patchawarra and Toolachee Formations (Cooper Basin) and the Birkhead Formation 7 APPEA Journal 006

13 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin (Eromanga Basin). One of the two Birkhead source rock samples is characterised by a Permian methylcarbazole signature. However, this particular sample behaves like a Permian sample based on several other geochemical parameters and appears to have been stained by a migrating Permian oil. Nevertheless, the distribution of methylcarbazoles in Cooper and Eromanga Basin sediments appears to be an effective discrimination tool, with a specificity far exceeding that of conventional hydrocarbon bio- and geo-markers. DST oil methylcarbazole signatures indicate that the DST oils represent a continuous mixture between pristine Jurassic and Permian endmember oils (Figure 10b). This is in agreement with previous studies on the origin of Cooper and Eromanga basin oils (Michaelsen and McKirdy, 1996, 001; Boreham and Summons, 1999; Yu, 000; Michaelsen, 00; Kramer et al, 004; Arouri et al, 004). Furthermore, the aforementioned observation that no DST oil bears a molecular signature which would suggest it has received any pre-permian input is confirmed by methylcarbazoles. When considering sequentially extracted residual oils (Fig. Figure 9. Mass chromatograms of methyl- (m/z 181) and dimethylcarbazoles (m/z 195) showing the typical distributions of these compounds in source rock extracts from the Cooper, Eromanga, and Warburton basins. Figure 10. a The Figure distribution 10. a the of distribution methylcarbazoles of methylcarbazoles in rock in extracts rock extracts from from the the Cooper ( ( : Toolachee Fm, : Patchawarra Fm), Eromanga ( ), and Warburton Toolachee Fm, (O) - basins. Patchawarra b Methylcarbazole Fm), Eromanga distributions of ( ), DST and oils (dashed Warburton field) reveal (O) Basins. that they are b mixtures of pure Cooper Basin (C) and Eromanga Basin (E) endmember distributions oils. c Methylcarbazole of DST oils (dashed distributions field) of reveal sequentially that extracted they are residual mixtures oils of suggests pure that as well as mixing of Cooper and Eromanga oils (cluster 1), Methylcarbazole Cooper Basin (C) mixtures and of Cooper Eromanga and Warburton-sourced Basin (E) end-member oils also exist oils. (cluster c ). Symbols Methylcarbazole in background plots refer to source rock extracts (+), oils (o), and residual distributions of sequentially oils (X) (modified extracted from Hallmann, residual 004). oils suggests that as well as mixing of Cooper APPEA Journal and Eromanga oils (cluster 1), mixtures of Cooper and Warburton-sourced oils also exist (cluster ). Symbols in background plots refer to source rock extracts (+), oils (o), and

14 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark Figure 11. Use of relative amounts of aromatic Araucariacaean biomarkers to differentiate source rock (+) and oil samples (o) from the Eromanga Basin (Jurassic and post-jurassic), and those from the Cooper and Warburton basins (pre-jurassic). The ratio of 1,7- vs. 1,6-dimethylcarbazole allows a further discrimination of the Cooper and Warburton samples. Several residual oils (x) exhibit a signature suggesting that they were sourced from the Warburton Basin (from Hallmann, 004). 10c), however, the picture changes. Residual oils do not form a continuum that represents mixing between a Jurassic and a Permian source, but cluster into four separate families. While one cluster (number 1 in figure 10 c) does correspond to a mixture between pure Permian and Jurassic oils, cluster number appears to represent mixing between oils derived from source rocks in the Cooper Basin and oils that bear a molecular signature indicative of their origin from within the Warburton Basin. A number of samples diverge from this cluster due to elevated or decreased amounts of 4-methylcarbazole (see red arrows in figure 10c). The deviating samples share no further common features, and, while some of these are characterised by pre-permian dimethylcarbazole signatures (see below), others did not contain enough dimethylcarbazoles for characterisation. If the degree of nitrogen shieldedness in methylcarbazoles influenced their fractionation and adsorption behaviour in the pore system of the reservoir (cf. Li et al, 1995), this would be reflected in the distribution of comparable sequentially extracted residual oil fractions, that is bitumens deriving from the first and last two pore-filling oil pulses should exhibit similar methylcarbazole distributions. The fact is that they do not. There is no recognisable pattern at all between the distribution of methylcarbazoles in terms of nitrogen shielding and the relative timing of their entrance into pore systems, implying that all four methylcarbazole isomers partition equivalently during reservoir wetting-related fractionation processes. The distribution of methylcarbazoles in sediments, oils and bitumens from the Cooper/Eromanga/Warburton Basin region can thus be interpreted as being governed almost exclusively by source facies. Dimethylcarbazoles are more complex and the shielding of their nitrogen heteroatom by two methyl groups has been shown to induce a different pattern of fractionation between fully shielded dimethylcarbazoles (1,8-dimethylcarbazole) and fully exposed isomers (Li et al,1995). The fractionation behaviour, however, converges Figure 1. The distribution of residual oils in the Gidgealpa Field, showing the chronological order in which they eluted. This order corresponds inversely to the order in which these oils filled the pore system. Fractions thus refers to the last oil that entered the pore system. 74 APPEA Journal 006

15 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin as the conformational similarity of the carbazole isomers increases, allowing other processes that steer dimethylcarbazole distributions to be recognised. The distribution of 1,7- and 1,6-dimethylcarbazole appears not to be controlled by fractionation processes or maturity. While rock samples from the Warburton Basin are characterised by high 1,7-/1,6-dimethylcarbazole ratios (>1.8), all Cooper and Eromanga rock extracts bear values lower than 1.4 for this ratio (Fig. 11). Combining this parameter with the distribution of Araucariacaean biomarkers allow for good discrimination between organic matter in sediments from the Warburton, Cooper and Eromanga Basins (Fig.11). While DST oils from reservoirs within the Cooper Basin are derived mainly from Permian source rocks, those from Eromanga reservoirs appear to be mostly mixtures of Permian- and Jurassic-sourced hydrocarbons. Again, no DST oils appear to have mixed with fluids that could have originated from the Warburton Basin. The distribution of 1,7- and 1,6-dimethylcarbazole in sequentially extracted residual oils, however, clearly shows that the Warburton Basin has generated petroleum and that these fluids have subsequently entered reservoirs in the overlying Cooper and Eromanga sequences of the Gidgealpa field where they mixed with locally sourced petroleums. The subordinate amount of pre-permian oil that is currently present in the producing reservoirs of the Gidgealpa field does not allow its recognition in either DST oils or whole reservoir core extracts wherein its diagnostic geochemical signature has become diluted beyond detectability. WARBURTON BASIN CHARGES Evaluation of the geochemical signature of separate residual oil fractions derived from one sample allows for ordering these, and thus the oil charges that formed them, in a relative chronological sequence. This technique was used successfully to reconstruct the charging history of the oil pools in the Gidgealpa field (Hallmann, 004; Hallmann et al, 006). Figure 1 shows that residual oil fractions exhibiting a pre-permian (Warburton Basin) signal are not confined to the first oil charge, as might be expected from the Warburton Basin s deep stratigraphic setting, but have contributed to the Cooper/Eromanga Basin oil play at differing intervals. However, the volume of discrete SFTE fractions is chosen individually and a small overlap of different charges will always be present. A Warburton Basin carbazole signal in a last pore-filling residual oil fraction, which commonly represents a considerable part of the rock extract, must thus not necessarily represent a major Warburton Basin oil charge. Instead, it can reflect the co-extraction of the latest (non-warburton) charge with a previously adsorbed Warburton Basin derived residual oil layer, the latter being highly enriched in polars relative to the oil representing the most recent charge. The result is a first extracted fraction consisting of, for example, non- Warburton saturates and aromatics and mixed Warburton and non-warburton resins. This contamination is, however, only encountered, if at all, in the first extracted residual oil fraction and does not foil the molecular information. Two scenarios can be responsible for this distribution of Warburton oils. Either a complex setting of source units has led to multiple oil charges from different kitchens, or Warburton oil was trapped intermittently and has leaked during a number of events into the overlying sedimentary sequence. While the varying MPI-calculated thermal maturities of up to 1.6% Rc that characterise Warburton Basin residual oils favour the first scenario, a leaking Warburton reservoir is not unrealistic and, since the Cooper and Eromanga sequences in the GMI area are well explored, suggests the possibility of Warburton Basin reservoirs that contain Warburton oils. The potential of Warburton Basin strata to bear qualitative reservoirs is not negligible as Sun (1999) found that the Warburton Basin is characterised by high fracture porosity. Oxidation and weathering of the upper Warburton Basin palaeosurface may have led to karst phenomena in limestones, which consequently created high porosity reservoirs. MIGRATION DISTANCE AND EFFICIENCY The relative migration distance of various oil charges in the study area has been determined using the ratio of benzo[a]carbazole versus benzo[a] + benzo[c]carbazole (Hallmann, 004; Hallmann et al, 006; Schwark et al, 006). The benzocarbazole a/(a+c) ratio (BCR) does not depend on either facies (Pr/Ph, Ts/Tm) or maturity (MPI, % ββ steranes) in the GMI area, and a strong positive relationship between the BCR and the absolute concentration of benzocarbazoles is observed (Fig. 13). In contrast to many relatively far migrated oils, which are found within the Jurassic (Hutton-Birkhead-Namur Formations) migration system and carry BCR values as low as 0.15, many of the residual oil fractions that have been shown to contain a pre-permian component are characterised by elevated BCR values between 0.3 and 0.6. All residual oils, whose 1,7-/1,6-dimethylcarbazole ratio is higher than 1.6, have an average BCR of While these values appear contradictory at first sight, they can be explained by structural faulting in the Warburton Basin underneath the Gidgealpa Ridge. The decrease of the BCR is not a pure indicator of relative migration distance but can be influenced by different lithologies, the amount of dispersed organic matter and the nature of the migration conduits (Hallmann et al, 006). Figure 14 shows that the Kalladeina Formation is overthrusted underneath the Gidgealpa Ridge and that Warburton strata are dipping steeply. Both the overthrust fault and the steep dip could give rise to very efficient migration conduits, leading to decreased fractionation of benzocarbazoles during secondary migration of pre-permian petroleum on its way up section to charge Permian reservoirs. CONCLUSIONS Within the Gidgealpa field organic matter in sedimentary rocks from the Warburton, Cooper and Eromanga Basins can be differentiated using hydrocarbon molecular parameters that determine the input of higher-plant- derived material APPEA Journal

16 C.O.E. Hallmann, K.R. Arouri, D.M. McKirdy and L. Schwark Figure 13. Strong positive correlation between the benzo[a]carbazole/benzo[a]- + benzo[c]carbazole ratio (BCR) in oils and their absolute concentration of benzocarbazoles. Both the BCR and the concentration of benzocarbazoles are thought to decrease with increasing relative migration distance. Five samples that exhibit elevated BCR values are derived from strata containing abundant indigenous organic matter, thereby contaminating the far migrated signature of oils with their non-migrated indigenous signal. The low absolute amount of carbazoles in far migrated oils makes them particularly susceptible to contamination (from Hallmann, 004). Figure 14. The structure of the Warburton Basin underneath the Gidgealpa Ridge showing the presence of a marked overthrust. The combination of a major fault and steeply dipping strata may account for the diminished fractionation of carbazoles observed in Warburton-sourced residual oils (modified from Roberts et al, 1990). 76 APPEA Journal 006

17 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin (Warburton vs. Cooper & Eromanga) and post-triassic material derived from Araucariacaean conifers (Warburton & Cooper vs. Eromanga). DST and production oils exhibit geochemical signatures indicative of them being mixtures of primary crude oils generated from Cooper and Eromanga basin source rocks. No affinity of these DST or production oils to organic matter preserved in the Cambro-Ordovician sediments of the underlying Warburton Basin is evident in their hydrocarbon molecular signatures. Alkylated carbazoles in source rock extracts, oils, and sequentially recovered reservoir bitumens from the Cooper, Eromanga basins and Warburton basins at Gidgealpa are a function of source facies only and exhibit high accuracy in discriminating between the indigenous organic matter of the three basins. Residual oils that were sequentially recovered from intact sandstone core plugs represent polar-enriched adsorption products of oils that were present in the pore system during discrete time-slices, thereby allowing the discrimination of multiple stages of a reservoir s filling history and the separate analysis of different oil charges. A significant number of residual oils exhibit molecular geochemical signals suggesting that they were generated from the organic matter present in Warburton Basin strata. This is the first demonstration that source rocks within the under-explored Warburton Basin have actually generated and expelled crude oil. These residual oils comprise only 1 5% of the total bitumen present in the pore space of the Permian and Jurassic reservoirs of the Gidgealpa field and hence would be diluted beyond detectability when using conventional, destructive extraction techniques. The oils that carry a Warburton signal derive from differing pore-filling oil pulses, thereby suggesting that they might have been intermittently stored in reservoirs within the Warburton Basin before spilling into the overlying sedimentary sequence. The possibility of such oil-bearing reservoirs should be taken into consideration during future exploration. ACKNOWLEDGEMENTS This paper is based on work undertaken by Christian Hallmann for his M.Sc. degree at the University of Cologne. His research project was part of a wider investigation: Conditions And Effects Of Hydrocarbon Fluid Flow In The Subsurface Of The Cooper/Eromanga Basin, which was financed by ARC SPIRT Grant C to David McKirdy, Detlev Leythaeuser and Lorenz Schwark. Additional funding was provided by PIRSA and Santos Limited. The authors thank Yassin Hardi, Markus Schmidt, Alexandra Richter, Bianca Stapper and Hanna Cieszynski (University of Cologne) for their invaluable technical assistance. 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21 A new perspective on exploring the Cooper/Eromanga petroleum province evidence of oil charging from the Warburton Basin THE AUTHORS Christian Hallmann received a MSc degree in organic geochemistry from the University of Cologne, Germany, in early 005. In his diploma project he worked on the fractionation pattern of polar petroleum compounds during secondary petroleum migration in the Cooper/Eromanga basins. Christian is currently undertaking a PhD in the Centre for Applied Organic Geochemistry at Curtin University of Technology, studying the alteration of petroleum by its subsurface interaction with water. Parallel to his studies he works part-time for Woodside Energy s exploration department. Christian is a member of EAOG, AAPG and PESA. His scientific interest focusses on molecular organic petroleum geochemistry, molecular microbial ecology and the origin/evolution of life. Khaled Arouri has a PhD in petroleum geochemistry and basin modelling (1996, Adelaide University), and a MS in petroleum geology and geochemistry (199, University of Jordan). He has held teaching, research and consultancy positions in Jordan, Australia and the United Arab Emirates before joining Saudi Aramco s research and development centre in late 005. His work focusses on petroleum systems, studies of hydrocarbon generation, migration and reservoir filling/compartmentalisation, oil-source correlations and the integration of geochemistry as a tool in exploration. David McKirdy is a graduate of the University of Adelaide (BSc Hons, MSc) and the Australian National University (PhD). Since 1970 he has held positions with the Bureau of Mineral Resources, the South Australian Geological Survey, Conoco Inc., and AMDEL Ltd. In 1987 he returned to Adelaide University where he taught for 18 years before recently retiring as an associate professor. In 1999 he was a guest professor at the University of Cologne. Now, as an Honorary Visiting Research Fellow, he continues to supervise Honours and PhD students while undertaking research in the fields of source rock and petroleum geochemistry, the use of organic geochemistry and isotope chemostratigraphy in basin analysis, and the study of Holocene climate change. He is a member of the European Association of Organic Geochemists, GSA and PESA. Lorenz Schwark holds a MSc in geology (1989) and a PhD in natural sciences (199) from the Technical University of Aachen. Between 1993 and 1999 he was an assistant professor at Cologne University, where he built up the Organic Geochemistry Laboratory. Since 000 he has been an associate professor, and since 004 a full professor at the same institution, where he teaches environmental and petroleum geochemistry. His special interests are the characterisation of black shale/source rock depositional environments; the study of petroleum migration and biodegradation via molecular tracers in carrier and reservoir rocks; palaeoclimatology using geochemical proxies; and environmental pollution. He is a member of the European Association of Organic Geochemists, and an Associate Editor of their journal Organic Geochemistry. APPEA Journal