Petroleum geology of South Australia. Vol. 2: Eromanga Basin. 1 CHAPTER 10 Hydrocarbon generation and migration TB Cotton and DM McKirdy INTRODUCTION .......................................................................................................................................................... 2 HYDROCARBON GENERATION................................................................................................................................. 2 Eastern Eromanga Basin .............................................................................................................................................. 2 Western Eromanga Basin ............................................................................................................................................. 3 ORIGIN OF EROMANGA BASIN OIL .......................................................................................................................... 3 OIL ALTERATION AND MIXING .................................................................................................................................. 4 MIGRATION.................................................................................................................................................................. 5 CHARGE HISTORY ..................................................................................................................................................... 6 Gidgealpa Field............................................................................................................................................................. 6 Strzelecki Field.............................................................................................................................................................. 7 Murteree Ridge ............................................................................................................................................................. 8 FIGURES ...................................................................................................................................................................... 9 TABLE 10.1 Source affinity and thermal maturity of DST oils and SFTE residual oils from Eromanga and Cooper Basin reservoirs (after McKirdy et al., 2005) ....................................................................................... 5
Transcript
Petroleum geology of South Australia. Vol. 2: Eromanga Basin. 1
CHAPTER 10 Hydrocarbon generation and migration TB Cotton and DM McKirdy
INTRODUCTION ..........................................................................................................................................................2 HYDROCARBON GENERATION.................................................................................................................................2 Eastern Eromanga Basin..............................................................................................................................................2 Western Eromanga Basin.............................................................................................................................................3 ORIGIN OF EROMANGA BASIN OIL ..........................................................................................................................3 OIL ALTERATION AND MIXING..................................................................................................................................4 MIGRATION..................................................................................................................................................................5 CHARGE HISTORY .....................................................................................................................................................6 Gidgealpa Field.............................................................................................................................................................6 Strzelecki Field..............................................................................................................................................................7 Murteree Ridge .............................................................................................................................................................8 FIGURES......................................................................................................................................................................9 TABLE 10.1 Source affinity and thermal maturity of DST oils and SFTE residual oils from Eromanga and
Cooper Basin reservoirs (after McKirdy et al., 2005).......................................................................................5
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INTRODUCTION This chapter aims to provide an overview of recent research and new insights into the generation and migration of hydrocarbons within the active petroleum systems of the Eromanga Basin in South Australia. Work on oil migration and mixing undertaken by the Organic Geochemistry in Basin Analysis Group (OGBA) at the University of Adelaide (McKirdy et al., 2005), major initiatives including the National Geoscience Mapping Accord Cooper–Eromanga Basin Project, together with various thermal history and geochemical studies commissioned by PIRSA, have provided a greater understanding of the operation of these systems. Detailed compositional analysis of source rocks, drillstem test (DST) oils and residual oils using gas chromatography – mass spectrometry (GC–MS) and other standard methods, combined with new techniques such as sequential flow-through solvent extraction (SFTE) of residual oils from core plugs (Schwark et al., 1997), have enabled researchers to better understand not only the source affinity and migration pathways of the oils but also the charge history of their host Jurassic and Cretaceous reservoirs in the Cooper–Eromanga region of South Australia. It has now been established that source rocks within both the Eromanga and underlying Cooper Basin sequences have contributed to oil accumulations in Eromanga Basin reservoirs and that multiple charge events and mixing of oils has occurred in many instances (Alexander et al., 1996; Boreham and Hill, 1998; Boult et al., 1998; Michaelsen and McKirdy, 2001; Michaelsen, 2002; Arouri et al, 2004; Kramer et al., 2004). At least four episodes of regional hydrocarbon generation have taken place (Deighton et al., 2003; Arouri et al., 2004) between the Permian and Tertiary with the majority generated in the mid-Cretaceous (Deighton and Hill, 1998; Deighton et al., 2003). Many reservoirs have been charged from local source rocks with only short migration paths (Michaelsen and McKirdy, 1996; Kramer et al., 2004). Others, as evidenced by recent commercial oil discoveries at the margins of the underlying Cooper Basin, have required extensive migration of oil from deeper source regions, in part within the open aquifer systems of the Eromanga Basin (Hunt et al., 1989; Toupin et al., 1997; Boult et al., 1998; Boreham and Hill, 1998; Boreham and Summons, 1999; Michaelsen and McKirdy; 2001; Altmann and Gordon, 2004). While recent research and exploration has focused on the eastern sector of the Eromanga Basin that overlies the Cooper Basin, the western sector above the Permo-Carboniferous Pedirka and Triassic Simpson basins (Fig. 1.2) has remained relatively unexplored. Limited well data and sparse modern seismic coverage (Carne and Alexander, 1997) has meant that the true extent and nature of the petroleum system(s) within these vast areas is yet to be realised. Despite this, the potential of the area is highlighted by the fact that oil generation is known to have occurred in the Simpson–Eromanga region with oil shows in five wells, including the DST recovery of oil from Poolowanna 1 (Fig. 1.2). An investigation by Ambrose et al. (2002) that utilised CSIRO Petroleum’s OMI (oil migration intervals), QGF (quantitative grain fluorescence) and GOI (grains with oil inclusions) technologies, resulted in the recognition of a palaeo-oil–gas column in the Poolowanna Formation at Colson 1. Early Permian source rocks are predicted to have expelled significant quantities of oil and gas during loading by the Winton Formation in the Cretaceous, creating an oil–gas column that leaked or was flushed during Tertiary folding. This upgrades the prospectivity of a large area in the vicinity of the northern Poolowanna and Madigan troughs where numerous pre-Winton Formation dip closures and a myriad of stratigraphic plays remain completely unexplored (Ambrose et al., 2002). While no new petroleum exploration wells have been drilled in the western sector of the Eromanga Basin since 1989, and despite a significant portion of the prospective area now being taken up by the Simpson Desert Conservation Park and unavailable for exploration as at 2005 (Fig. 2.12), the area remains one of South Australia’s most prospective frontier hydrocarbon provinces. HYDROCARBON GENERATION Eastern Eromanga Basin Known generation of hydrocarbons in the Cooper and Eromanga basins of South Australia has occurred principally from kitchen areas within the vicinity of the Patchawarra and Nappamerri structural troughs (e.g. Boreham and Hill, 1998; Deighton and Hill, 1998; Boreham and Summons, 1999; Deighton et al., 2003). Thermal modelling by Deighton et al. (2003) indicated that generation and expulsion of hydrocarbons from Eromanga and Cooper source rocks occurred primarily during the mid Cretaceous with minor amounts generated during the Tertiary and from
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Cooper Basin source rocks in the hottest and deepest parts of the Nappamerri Trough during the Permian (Figs 10.1, 10.2) The hydrocarbon expulsion curves for the principal Cooper and Eromanga source rocks indicate that the majority of hydrocarbons were generated and expelled from the Cooper Basin with only minor and localised generation from Eromanga sources. However, the authors did concede that poor prediction of early oil expulsion where source and reservoir rocks are in close proximity was a limitation of the modelling. The fact that a substantial proportion of the oil in Eromanga Basin reservoirs has been generated, at least in part, from intra-Eromanga source rocks (Michaelsen and McKirdy, 1996; Boult et al., 1998; Boreham and Summons, 1999; Michaelsen and McKirdy, 2001; Michaelsen, 2002), and in many instances locally derived (Michaelsen and McKirdy, 1996), would suggest that Deighton et al. (2003) have underestimated the contribution of Eromanga sourced oil to accumulations within the basin. The underlying Cooper Basin reservoirs contain numerous accumulations of both oil and gas. Most of the oil contains significant quantities of dissolved gas with no evidence of water washing (Hunt et al., 1989; Boreham and Hill, 1998). The majority of oil and wet gas is sourced primarily from the Patchawarra Trough, while predominantly dry gas is generated from the deeper and more thermally mature source rocks of the Nappamerri Trough (Fig. 4.9; Hunt et al., 1989; Boreham and Hill, 1998). While source rocks within the Eromanga Basin have been shown to contain both Type II/III (oil/gas-prone) and Type II (oil-prone) organic matter (Michaelsen and McKirdy, 1996), and gas is found at many levels throughout the Jurassic–Cretaceous sequence (Michaelsen and McKirdy, 2001), these occurrences of gas are insignificant when compared to those in the underlying Cooper Basin. This suggests that Eromanga source rocks typically have only reached maturities suitable only for oil generation. Western Eromanga Basin The two most prospective areas of the western Eromanga Basin are the Eringa and Poolowanna troughs where it overlies the Pedirka and Simpson basins (Fig. 1.2). While there has been only limited exploration drilling in both areas, the evidence for petroleum generation is strong. High-quality oil-prone source rocks have been identified in enough wells to imply their development over a wide area of the western Eromanga Basin (Michaelsen and McKirdy, 1996). Geochemical investigations have revealed excellent oil-prone source rocks in the Eringa Trough that have reached temperatures sufficient for petroleum generation (Alexander et al., 1996; Tingate and Duddy, 1996; Ambrose et al., 2002). In the Poolowanna Trough, hydrocarbon generation is proven by the existence of oil shows in five wells at the Simpson Basin level, including the DST recovery of two distinct types of oil from the Triassic Peera Peera and Jurassic Poolowanna formations in Poolowanna 1 (Wiltshire, 1978). In the northern Poolowanna Trough and Madigan Trough (Northern Territory), Early Permian source rocks are predicted to have expelled significant quantities of oil and gas during deposition of the Winton Formation (Ambrose et al., 2002). ORIGIN OF EROMANGA BASIN OIL Up to 70% of the oil within the Cooper–Eromanga region is trapped within the Eromanga Basin (Michaelsen and McKirdy, 2001). While the Hutton Sandstone is the primary oil reservoir unit within the basin, nearly all units from the Poolowanna to Murta Formation contain free-flowing oil reservoirs (Alexander, 1996a). The origin of this oil, whether from a Cooper or Eromanga source, has been widely debated and studied over many years. One of the pivotal reasons for this uncertainty has been that traditional biomarker studies of oils and source rocks have provided inconclusive results due to the similarity of the palaeo-depositional environments and preserved organic matter in the two basins (Michaelsen and McKirdy, 2001). Numerous studies over the last decade have confirmed the Birkhead, Murta and Poolowanna formations as the three main effective source rocks within the Eromanga Basin sequence (e.g. Alexander et al, 1988, 1992,1996; Michaelsen and McKirdy, 1989, 1996; Powell et al., 1989; Kagya, 1997; Boult et al., 1998, Michaelsen, 2002;). Previous authors suggested that the majority of the Eromanga Basin’s oil had been derived principally from Permian sources, and had migrated along faults and erosional subcrops into the overlying reservoirs (e.g. Heath et al, 1989; Jenkins, 1989). While geochemical evidence now suggests that in many instances Permian oil has indeed migrated into the overlying Eromanga Basin sequence, it is also widely accepted that a significant portion of this oil, up to 80% in the Birkhead Formation from Arrakis 1 (McKirdy et al., 2005), has been derived from local Eromanga
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sources (Michaelsen and McKirdy, 1996; Michaelsen and McKirdy, 2001; Arouri et al., 2004; McKirdy et al., 2005). As such, many authors (e.g. Boreham and Summons, 1999; Michaelsen and McKirdy, 2001) have found it convenient to define the principal petroleum systems within the Cooper–Eromanga region in terms of three source/reservoir couplets: (1) Cooper-sourced and reservoired, (2) Cooper-sourced and Eromanga-reservoired, (3) Eromanga-sourced and reservoired. Boreham and Summons (1999) further defined two major active petroleum systems within the Eromanga sequence, the Birkhead and Murta petroleum systems, that reflect individual contributions from the two separate sources. Further detailed studies of the Hutton–Birkhead reservoir–source couplet (Boult, 1996; Boult et al., 1998; Underschultz and Boult, 2004) describe the petroleum system operating within these specific units in the Gidgealpa area of the southwestern Cooper Basin. However, this Jurassic petroleum system is not restricted specifically to these units in all fields and Birkhead-sourced oil pools occur in other reservoir units of the Eromanga Basin. Various geochemical methods have been employed in attempts to determine the source affinity of the oils found in the Eromanga Basin. Both Michaelsen and McKirdy (1989) and Tupper and Burckhardt (1990) used the maturity contrast between Permian, Jurassic and Cretaceous source rocks in an effort to discriminate between oils of Eromanga and Cooper origin. Boreham and Summons (1999) attempted oil–oil and oil–source correlations using compound-specific isotopic analysis (CSIA) of n-alkanes, although Michaelsen and McKirdy (2001) subsequently queried the validity of their conclusions. Alexander et al. (1988) were the first to identify several age-specific biomarkers that could be used to differentiate between Permian and Jurassic–Cretaceous oils. These aromatic hydrocarbons (viz. 1,2,5-trimethylnaphthalene, 1-methylphenanthrene, 1,7-dimethylphenanthrene and retene) that are derived from the resin acids of araucariacean conifers have now been widely accepted as robust indicators of Jurassic–Cretaceous source affinity. The two bacterial biomarkers (viz. 25,28,30-trisnorhopane and 28,30-bisnorhopane), suggested by Jenkins (1989) and Alexander et al. (1996) to be capable of discriminating between Permian and Jurassic-sourced oils, are far less definitive. OIL ALTERATION AND MIXING Unlike the underlying Cooper Basin, oil reservoired in the Eromanga Basin sequence does not show regionally consistent trends in hydrocarbon type, composition and maturation (Boreham and Hill, 1998). Boreham and Summons (1999) noted that many oils in Cretaceous reservoirs are geochemically distinct from those in Jurassic reservoirs and appear to be less mature. However, kinetic studies of Cretaceous Murta source rocks indicate that oil expulsion has occurred at maturity levels similar to those of Jurassic and Permian sources. Boreham and Hill (1998) suggest that Murta-hosted oils are the result of in situ mixing of low- and high-maturity charges, the latter originating from deeper sources and hence being prone to secondary alteration during long-distance migration (see also Boreham and Summons, 1999). These authors identified migration fractionation (Curiale and Bromley, 1996) or evaporative fractionation (Thompson, 1987, 1988) as the process most likely to have contributed to the compositional variation evident within the oil pools of the Eromanga Basin. Rapid reduction in the confining pressure of upward-migrating petroleum fluids resulting in separate gas- and oil-rich phases, together with preferential leakage of lighter compounds through ineffective seals, are two mechanisms by which this could have occurred. Other workers (e.g. Vincent et al., 1985; Alexander et al., 1988; Powell et al., 1989) proposed that variations in the depositional environments and organic facies of local source rocks had been at least partly responsible for differences in the properties of Eromanga crudes. It was suggested by Heath et al. (1989) that geochemical differences between oils from these two basins might be attributed to gas stripping and water washing as Permian oil migrated into reservoirs within the Eromanga Basin. While there is strong evidence for water washing and degassing of oils during their migration through the Eromanga Basin’s aquifer system (Alexander et al., 1996; Boreham and Hill, 1998; Boreham and Summons, 1999; Michaelsen 2002; Altmann and Gordon, 2004), and previous groundwater modelling has indicated that extensive groundwater flow through the basin had probably occurred during the Tertiary (Toupin et al., 1997), the compositional variability of Eromanga oils cannot be attributed to these processes alone. The mixing of oils of different source affinity is now widely believed to have had a significant influence on the compositional variability of oil in Eromanga Basin reservoirs.
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Recognition of the mixing of Cooper and Eromanga oils is complicated by the existence of at least two distinct families of Permian oils (McKirdy et al., 1997; Boreham and Summons 1999; Michaelsen and McKirdy, 2001). Michaelsen (2002) attributed these two families to the second (c. 105 Ma) and third (c. 90 Ma) expulsion events of Deighton and Hill (1998) and Deighton et al. (2003), (see also Figs 10.1 and 10.2). The exceptionally mature, condensate-like (46–50 °API gravity) Family 1 oils were derived principally from Permian coals and are restricted to the northern Patchawarra Trough, while the hopanoid biomarkers of the heavier (34–36 °API gravity) Family 2 oils indicate their derivation from shale sources with a much wider distribution across the region (Fig. 10.3; Michaelsen and McKirdy, 2001; Michaelsen 2002). In addition, CSIA of their n-alkanes reveals a difference between crude oils originating in the Lower Permian (Patchawarra) and Upper Permian (Toolachee) coal measures (Boreham and Summons, 1999). Moreover, recently acquired geochemical evidence has pointed to possible contributions from underlying Cambro-Ordovician Warburton Basin sources to oil accumulations in several fields across the Eromanga Basin (e.g. Boreham and Summons, 1999; Arouri et al., 2004; Hallmann et al., 2006). Parallel with the development of models and ideas regarding the mixing of oils within Eromanga reservoirs, much research has been focused on trying to quantify the relative inputs of Permian and Jurassic–Cretaceous oil to any one accumulation. An understanding of the proportional contributions from the various sources thus enables the timing and sequence of events that lead to migration and reservoir filling to be better understood. Jenkins (1989) proposed using relative abundances of selected bacterial biomarkers to estimate the amount of Eromanga-sourced oil. Several authors including Michaelsen and McKirdy (1996) and Alexander et al. (1996) have questioned this approach on the grounds that these biomarkers (viz. norhopanes) are not restricted to Jurassic or younger source rocks, whereas the conifer-derived aromatic hydrocarbons of Alexander et al. (1988) have proved to be far more reliable in distinguishing between Cooper- and Eromanga-sourced oils (Arouri et al., 2004). Boreham and Summons (1999) used n-alkane isotopic data to assess the relative contributions and concluded their method was robust provided the Eromanga component was >25% in oils of mixed origin. Yu (2000) and Yu et al. (2000) proposed a method involving maturity measurements on the light (C5–C14) and heavy (C15+) ends of the crude oil and calculation of a detailed compositional mass balance that takes into account the observed chemical and/or isotopic variation between the oil in question and the end-member oils which mixed to produce it. A source-maturity cross-plot based on methylphenanthrenes, incorporating one of the araucariacaen biomarkers of Alexander et al. (1988), was devised by Michaelsen and McKirdy (2001) to enable the semi-quantitative determination of the relative contributions of Permian and Jurassic–Cretaceous oils to Eromanga reservoirs (Figs 10.4, 10.5; Michaelsen and McKirdy, 2001). Adopting this approach, Michaelsen (2002) concluded that the oils he analysed from Eromanga reservoirs in South Australia were either mixtures of Permian and Jurassic–Cretaceous oils, or entirely of Jurassic–Cretaceous origin (Table 10.1). Calibration of this technique by Arouri and McKirdy (2005) using artificial blends of end-member Permian and Jurassic oils from the Moorari Field revealed that the mixing curves of Michaelsen and McKirdy (2001) overestimate the relative contribution of Eromanga oil. Thus, many of the oils considered entirely or mostly Jurassic–Cretaceous by Michaelsen and McKirdy (2001) and Michaelsen (2002) are now shown to contain Permian inputs of up to 50% (Table 10.1). Table 10.1 Source affinity and thermal maturity of DST oils and SFTE residual oils from Eromanga and Cooper Basin reservoirs (after McKirdy et al., 2005). Use this link to view the table.
MIGRATION Long-distance migration of Permian-sourced oil has been suggested for many of the accumulations in the Eromanga Basin (e.g. Hunt et al., 1989; Lowe-Young et al., 1997; Toupin et al., 1997; Boreham and Summons, 1999; Altmann and Gordon, 2004). Giving credence to this interpretation are numerous recent commercial oil discoveries within the Eromanga Basin sequence far away from the deeper troughs (i.e. hydrocarbon kitchens) and beyond the edge of the Cooper Basin in areas previously deemed too risky due to the lack of perceived local generative potential. Conduits for the secondary migration of hydrocarbons from mature Permian source rocks have been developed along faulted anticlinal trends and basin pinchouts (Passmore, 1989; Heath et al., 1989) and in areas where regional seals are thin, absent or ineffective (Heath et al., 1989). Extensive lateral migration of both Permian- and Eromanga sourced-oil becomes possible where it has entered permeable carrier beds within the
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open aquifer system of the Eromanga Basin. Boreham and Summons (1999) suggested that access to migration fairways for Permian oil was one of the principal controls on the distribution of oil accumulations in the Eromanga Basin. Analysis of fluid inclusions and mathematical modelling by Toupin et al (1997) showed that, although present-day hydraulic gradients in the Cooper–Eromanga region are too small to flush hydrocarbons from structural traps, significantly higher gradients existed during the Tertiary. It was suggested that this higher groundwater flow had possibly focused Eromanga hydrocarbons toward the southern end of the Cooper Basin where the largest number of oil reservoirs are situated. Altmann and Gordon (2004) proposed that secondary alteration processes during long-range migration from the deeper generating areas of the Patchawarra Trough were responsible for differences in oil properties across the southwestern Cooper and Eromanga basins (Fig. 10.6). Oils produced from wells drilled along the flank of the Patchawarra Trough, including the commercial Sellicks 1 (Patchawarra) and Christies 1 (Birkhead) discoveries were each shown to have molecular compositions consistent with their origin from a terrestrial oxic-source facies. Differences in their physical characteristics (viz. API gravity and gas to oil ratios) are consistent with the greater degree of water washing in the Birkhead oil pool at the Christies locality . A more detailed geochemical comparison of the oils from these two fields by Errock (2005) reveals that the common lower Patchawarra source inferred by Altmann and Gordon (2004) is only partly correct. Using the calibrated mixing model of Arouri and McKirdy (2005), she confirmed the intra-Patchawarra origin of the Sellicks oil while showing that the Christies crude is actually a mixture of Permian (~60%) and Jurassic (~40%) hydrocarbons, the latter most likely derived from source beds within the Birkhead Formation. Alexander et al. (1996) investigated water washing and progressive depletion of soluble aromatic compounds within oils of the Cooper–Eromanga Basin system as a means by which distances of secondary migration could be measured. It was argued that migration distance could be linked to the abundances of phenanthrene and dibenzothiophene relative to the less soluble tetramethylnaphthalenes , with depletion of the former compounds reflecting increased exposure of the oil to an aqueous phase during migration. This approach assumes that the oils being compared contained the same relative abundances of the reference compounds at the time of primary migration. One of the key findings of this study was that oils from the stacked reservoirs of the Keleary and Big Lake fields (Fig. 1.3) showed a pattern of increased water washing with higher stratigraphic position. The clear implication is that most migrated oils are pooled within the youngest reservoir of each field. CHARGE HISTORY While thermal modelling and detailed geochemical analysis of DST oils have pointed to numerous hydrocarbon expulsion events and multiple charge episodes of many Eromanga Basin reservoirs, only recently have attempts been made to unravel their filling histories. The use of a Solvent Flow-Through Extraction (SFTE) cell, developed by the University of Cologne (Schwark et al., 1997), has enabled researchers at the University of Adelaide to reconstruct the charge histories of numerous Eromanga Basin reservoirs and to better understand the processes involved in secondary oil migration. The SFTE cell (Fig. 10.7) sequentially recovers individual oil charges, in the form of free and adsorbed oil from reservoir core plugs in the reverse order to which they are assumed to have entered the pore network. Traditional geochemical analyses are subsequently performed on each of the extracted residual oils allowing their comparison with known oils and source rocks. A more comprehensive description of the SFTE technique and its use to determine the charge histories of Eromanga Basin reservoirs is given in numerous publications and several theses (Yu 2000; Arouri et al., 2004; Hallmann, 2004; Kramer et al., 2004; McKirdy et al., 2005; Hallmann et al., 2006). Gidgealpa Field The multi-reservoir Gidgealpa oil field is located at the southern end of the Gidgealpa–Merrimelia–Innamincka structural ridge that separates the Nappamerri and Patchawarra troughs, the two principal hydrocarbon-generating regions within the South Australian sector of the Cooper and Eromanga basins (Figs 1.3, 4.9). The field comprises two domes separated by a shallow saddle (Fig. 10.8) with ~38 m of closure (McIntyre, 1989; Boult et al., 1998). Oil is reservoired within the Namur and Hutton sandstones, and Birkhead and Poolowanna formations in the
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Eromanga Basin. In the underlying Cooper Basin sequence, gas is produced from the Tirrawarra Sandstone and the Patchawarra and Toolachee formations. A thin oil leg also exists beneath a gas accumulation in the Tirrawarra Sandstone of the southern dome and in the Patchawarra Formation of the northern dome (McIntyre et al., 1989). Oils recovered from wells in the Gidgealpa Field clearly show a compositional distinction between Cooper and Eromanga reservoirs (Boreham and Summons, 1999; Michaelsen, 2002). Biomarker analyses, seal studies and maturation modelling indicate that the Gidgealpa southern dome has been charged from at least two discrete generative pulses (Boult, 1996; Boult et al., 1998). The first pulse originated mostly from the Nappamerri Trough, with a lesser contribution from the Patchawarra Trough, between 90 and 70 Ma. Recent increases in geothermal gradient for the Cooper–Eromanga region have possibly provided a second charge within the last million years (Boult et al., 1997). Subtle differences in the chemical properties of oils from Hutton, Birkhead and Namur reservoirs also possibly reflect two separate oil charges (Michaelsen, 2002). As for other regions of the Cooper and Eromanga basins, the origin of the Eromanga-pooled oil and gas at Gidgealpa has been the subject of much debate. Heath et al. (1989) suggested that Permian oil had migrated up section into the Eromanga reservoirs of the Gidgealpa Field. The fact that there is very little gas and gas to oil ratios are low within these reservoirs was attributed to gas stripping and water washing during migration. Boult (1996) argued against this idea on the basis that there is a lack of any significant oil within the Permian sequence at Gidgealpa. What little oil there is in the Patchawarra Formation has a geochemical signature different from that of the Jurassic oil. Significant concentrations of araucariacean biomarkers and unusual thermally labile hopanes in Hutton oil from Gidgealpa 17 (Ryan, 1996; Boult et al., 1998) make it unlikely that this live oil had migrated from hotter Permian rocks directly below. The argument for a predominantly Jurassic source (Boult 1996; Ryan, 1996; Boult et al., 1998) was supported by the work of Michaelsen and McKirdy (2001), who concluded, through the use of their source–maturity cross-plot (Fig. 10.4), that while the pooled oils were predominantly Eromanga-sourced, they are blended to varying degrees with Permian oil (Table 10.1), a view also supported by the n-alkane CSIA data of Boreham and Summons (1999). With further work and refinement of the Michaelsen and McKirdy (2001) mixing curves by Arouri and McKirdy (2005), the proportion of Eromanga-sourced oil was significantly downgraded, particularly within the Hutton, Birkhead and Namur reservoirs (Table 10.1). Many of the oils that were previously interpreted as entirely or dominantly of Jurassic origin are now deemed to be up to 70% Permian (Table 10.1). Studies of SFTE residual oils from reservoirs in the southern dome at Gidgealpa (McKirdy et al., 2005) and, in particular, comparison of their nitrogen-containing dimethyl- and benzocarbazole signatures with those of local source rocks and DST oils (Hallmann, 2004; Hallmann et al., 2005, 2006, in prep.) have provided the latest breakthroughs in our understanding of the charge history of this iconic oil and gas field. These include the first conclusive evidence of pre-Permian (Warburton) oil charges to its Hutton, Toolache and Tirrawarra reservoirs; and the recognition of five discrete charge events. Strzelecki Field Several wells within the Strzelecki oil and gas field, located along the southern margin of the Nappamerri Trough (Fig. 10.9), were the focus of a study by Kramer et al. (2004) to investigate the charge history of its oil-bearing reservoirs. Residual oils from core plugs of the Hutton Sandstone, Birkhead Formation and Namur Sandstone were extracted using the SFTE technique (Schwark et al., 1997) and their aromatic hydrocarbon fractions analysed by GC-MS. The resulting data were then displayed on the source and maturity cross-plots of Alexander et al. (1988) and Arouri and McKirdy (2005). The residual and DST oils examined by Kramer et al. (2004) were, with the exception of the Strzelecki 10 (Toolachee) crude, all mixtures of Permian (65–80%) and Jurassic (20–35%) hydrocarbons. Comparison of the n-alkane isotopic profiles of the Namur, Birkhead and Toolachee crudes (Boreham and Summons, 1999) suggests that coals and carbonaceous shales of the Toolachee Formation were the most likely source for the majority of Permian charge within the Strzelecki Field. Similarities between the maturity and source affinity of free and adsorbed oils, extracted using SFTE, led Kramer et al. (2004) to conclude that the oil columns within the field were either filled in a single charge event, or that the final reservoir charge had
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occurred long enough ago for complete homogenisation of any multiple charges to have taken place. A slight upward decrease in oil maturity within the stacked reservoirs of the Strzelecki Field was interpreted to indicate the sequential upward filling of traps by leakage from lower reservoirs which were being progressively filled from more mature and distant source rocks. Murteree Ridge The Murteree Ridge separates the Nappamerri and Tenappera troughs in the southern Cooper–Eromanga region and is considered to be the focus of hydrocarbon migration from these two major kitchen areas (Arouri et al., 2004). The ridge was a basement high during deposition of the Eromanga Basin sequence along which no Cooper Basin sediments are preserved (Fig. 10.10; Gravestock and Jensen-Schmidt, 1998). All its oil pools are located entirely within the Eromanga Basin sequence. DST oils from fields along the Murteree Ridge, including those at Alwyn, Biala, Limestone Creek, Kobari, Nungeroo and Ulandi (Fig. 10.11), were examined by Michaelsen (2002) who showed that in a number of instances oils reservoired in the Namur Sandstone and Murta Formation are very waxy and similar to those in the Patchawarra Formation at Daralingie 16 down-dip in the Nappamerri Trough. This suggests that Permian-derived oils have more than likely migrated from the deeper Cooper Basin into the reservoirs along the Murteree Ridge. Subsequent detailed analysis of DST samples and residual oils recovered by SFTE from core plugs of sandstones in the reservoir units of these and other fields along or adjacent to the Murteree Ridge (viz. Cadna-owie, Murta, McKinlay, Namur and Hutton: Arouri et al., 2004) showed that they contain hydrocarbons of mixed Cooper and Eromanga origins in proportions that vary between 55 and 80% Permian (using the calibrated mixing model of Arouri and McKirdy, 2005; Table 10.1; Fig. 10.12). Three Permian charge episodes, possibly linked to the oil expulsion events at 105, 90 and 20–0 Ma (Fig. 10.1), can be recognised in the charge histories of the Cretaceous reservoirs in the Biala, Jena, Limestone Creek, Nungeroo and Ulandi fields (Fig. 10.13). This multiple charge history is most clearly illustrated by the residual oils from the McKinlay and Namur reservoirs in Biala 7 (top panel, Fig. 10.13). Here the Permian pulses appear to be superimposed on a background charge of Jurassic and/or Cretaceous oil, while the DST oil from all three reservoirs (Murta, McKinlay and Namur) is ~75% Permian sourced. The shallowest oil pools atop the ridge (Cadna-owie, Murta) have the greatest Permian inputs, which represent the first escape of low-maturity fluids from the Cooper Basin into the overlying Eromanga succession. Subsequent pulses progressively displaced this initial Permian charge upwards into shallower traps. This explains why, at each stage of their charge histories, the three reservoirs of the Jena Field maintain the same relativity of Permian input, viz. Murta > McKinlay > Namur (second panel, Fig. 10.13). Analysis of DST oils from the Hutton reservoirs of the Kerinna and Mudlalee fields in the immediate vicinity of the Murteree Ridge, and from the Murta reservoir of the Kobari Field further south (Fig. 10.11), likewise showed them to be of mixed Cooper and Eromanga source affinity (Arouri et al., 2004). The Permian component of the oil pooled in these fields increases, while its maturity decreases, with increasing distance from the Murteree Ridge.
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Petroleum geology of South Australia. Vol. 2: Eromanga Basin. 9
FIGURES 10.1 Oil expulsion vs time, Cooper Basin (after Deighton et al., 2003). (202700_084)
10.2 Gas expulsion vs time, Cooper Basin (after Deighton et al., 2003). (202700_085)
10.3 Distribution of Family 1 and Family 2 oils in the southwestern Cooper Basin, South Australia, with respect to Tupper and Burckhardt’s (1990) isoreflectance contours for the base of the Patchawarra Formation (after Michaelsen and McKirdy, 2001). (202700_088)
10.4 Simple model of hydrocarbon mixing using the cross-plot 1-methylphenanthrene/9-methylphenanthrene versus 2-methylphenanthrene/1-methylphenanthrene for Cooper–Eromanga oils. Mostly Permian sourced = c. 95–68% Permian; Mixed = 67–34% Permian; Mostly Jurassic or Cretaceous sourced = 33–c. 5% Permian. (After Michaelsen and McKirdy, 2001.) (202700_089)
10.5 Distribution of Eromanga Basin oils in South Australia based on ‘mixing curve 1’ and ‘mixing curve 2’ (after Michaelsen and McKirdy, 2001). (202700_090)
10.6 Schematic representation of the Patchawarra Trough showing the migration of oil towards the Patchawarra sub-crop margin and its increased susceptibility to water washing with exposure to the open aquifer system of the Great Artesian Basin (after Altmann and Gordon, 2004; Errock, 2005). (202700_091)
10.7 SFTE cell device. (a) Whole-core extraction cell. (b) Cell with arrows indicating solvent flow. (c) Schematic oil-filled pore illustrating ‘free oil’ and ‘adsorbed oil’. (After Kramer et al., 2004; Schwark et al., 1997.) (202700_092)
10.8 Cross-section of the Gidgealpa oil and gas field showing possible migration pathways and the control of the Triassic seal on migration pathways (after Boult et al., 1998). (202700_093)
10.9 Cross-section of the Strzelecki oil and gas field. Line of section located relative to the oil–water contact of the Hutton reservoir (after Heath et al., 1989; Kramer et al., 2004). (202700_094)
10.10 Cross-section of the Murteree Ridge oil fields (after Heath et al., 1989). (202700_095)
10.11 Seismic section across the Murteree Ridge showing truncation of Permian strata by Mesozoic erosion and locations of fields (after Arouri et al., 2004). (202700_096)
10.12 Estimates of the degree of mixing of Cooper- and Eromanga-derived hydrocarbons in fields along and adjacent to the Murteree Ridge, based on the model of Michaelsen and McKirdy (1989, 2001) and manual blending of end-member oils (dashed curve is from Arouri and McKirdy, 2005). (After Arouri et al., 2004). (202700_097)
10.13 Hydrocarbon filling sequence of the Murteree Ridge fields as inferred from the analysis of their residual and DST oils. Estimates of Permian hydrocarbon contributions derived from the manual-mixing curve (Arouri and McKirdy, 2005) are compared to those made based on Michaelsen and McKirdy’s (1999, 2001) model. (After Arouri et al., 2004.) (202700_098)
