Area NT07-2
Money Shoal Basin
Petroleum Potential
To date, no commercial discoveries have been made in the Money Shoal and Arafura basins, but there are numerous hydrocarbon indications in wells drilled in the Goulburn Graben (Figure 2). Arafura 1 and Goulburn 1 had the most promising results with oil shows, and a gas show in Arafura 1. Chameleon 1, Cobra 1A, Kulka 1, Money Shoal 1, Tasman 1 and Tuatara 1 all contain oil indications in Mesozoic and Palaeozoic reservoirs (Miyazaki and McNeil, 1998). A review of available data sets together with new data and interpretations (Earl, 2006; Struckmeyer, 2006a, b), and results from a recent survey investigating potential hydrocarbon seepage in the Arafura Basin (Logan et al, 2006) show that the region contains not only all the required essential petroleum systems elements to generate, expel and trap hydrocarbons, but also evidence that this generation and expulsion has occurred.
Source rocks
Based on RockEval total organic carbon (TOC) data (Figure 11), the Arafura and Money Shoal basins contain several units with potential source rocks (Boreham, 2006; Struckmeyer, 2006a, b). In the western Goulburn Graben of the Money Shoal Basin, which underlies the southeastern part of the release area, the oil window typically occurs at depths between 2400 and 2900 m. None of the three wells in or near the release area (Tuatara 1, Cobra 1 and Kulka 1) intersected sediments older than Permo-Carboniferous, but seismic data show that older Palaeozoic rocks intersected by wells in the eastern Goulburn Graben are also present in the release area (Figure 3). Descriptions of the source potential of these rocks are based on wells from the eastern Goulburn Graben.
Samples from the Cambro-Ordovician Goulburn Group contain up to 8.6% TOC contents (Figure 11). The higher values represent migrated oil and solid bitumen (Keiraville Konsultants, 1984; Sherwood et al, 2006) rather than dispersed organic matter as reported in previous publications (Bradshaw et al, 1990, Edwards et al, 1997). A recent oil-source correlation study in the Georgina Basin (Boreham and Ambrose, 2005) identified three Middle to Late Cambrian petroleum systems related to source rocks of algal/bacterial origin. One of these, the early Middle Cambrian Thorntonia(!) Petroleum System, has similar geochemical and isotopic characteristics to oil stains in Early Palaeozoic rocks at Arafura 1 and Goulburn 1 (Boreham and Ambrose, 2005). This suggests that the effective source rock in the Arafura Basin is likely to occur in the Jigaimara Formation, which is an age equivalent of the Thorntonia Limestone in the Georgina Basin. The presence of abundant interstitial bitumen in association with oil stains in Early Palaeozoic samples is indicative of a multi-charge history from a prolific source nearby (Sherwood et al, 2006). Potential source rocks may also be present within the Neoproterozoic Wessel Group; however, no data are available for this section.
A limited number of samples from the Devonian suggests a generally poor source potential for this section; however, one sample at Arafura 1 contains 0.85% TOC which consists predominantly of lamalginite (Sherwood et al, 2006). This confirms that potentially fair source rocks are present within Devonian marine calcareous mudstones. Higher TOC values in other samples reflect the presence of bitumen (Figure 11). Based on well data, the Early Palaeozoic succession is typically mature to overmature for hydrocarbon generation.
Good to very good potential source rocks are also present in the Permo-Carboniferous Kulshill Group equivalent. The typical TOC range is <0.4 to 3% with hydrogen index (HI) values of up to 321 mg hydrocarbons/gTOC (Figures 11 and 12), but several samples in the central Goulburn Graben contain up to 9% TOC, comprising land plant-derived organic matter such as vitrinite, sporinite and liptodetrinite (Sherwood et al, 2006). Based on vitrinite reflectance data at Kulka 1 (0.9-2.4%), the Kulshill Group in the western Goulburn Graben is mature to overmature for oil generation and mature for gas generation.
The Jurassic section contains good to excellent potential source rocks and has a typical TOC range of 0.5-8% and HI values of up to 454 mg hydrocarbons/gTOC (Figures 11, 13 and 14). Several coaly units with TOC values up to 60% are also present, particularly in the Early-Middle Jurassic Troughton Group equivalent. Sediments of this age (Plover Formation) provide the source rocks for gas/condensate accumulations in the nearby Bonaparte Basin (eg Preston and Edwards, 2000). In the Arafura Basin region, the Jurassic section is mostly immature for oil generation; however, it reaches oil maturity in the westernmost Goulburn Graben (VR values of 0.6-0.79% at Tuatara 1) and is probably mature for oil generation in the western half of the release area. Here, the lower Flamingo Group should also be marginally mature to mature for oil generation. Cretaceous potential source rocks contain up to 5% TOC, but are immature for hydrocarbon generation.
Reservoir rocks
Potential reservoir rocks in the Arafura Basin (Figure 15) include shallow marine limestones and dolomites of the Cambro-Ordovician Goulburn Group, and terrestrial to fluvio-deltaic interbedded sandstones and mudstones of the Devonian Arafura Group and Permo-Carboniferous Kulshill Group equivalent. The Goulburn Group dolomite could be an important potential reservoir in the region, hosting an oil and gas show in Arafura 1 and oil indications in Goulburn 1. The unit has a maximum porosity of 7.7%, but averages about 2% in sections lacking significant secondary porosity (Figure 15). Permeability values are also generally low. As a result, reservoir quality in this unit relies on the development of secondary porosity through features such as vugs and fractures. These features are common, as evidenced by repeated mud losses, increases in drilling rates, variable caliper logs and drilling breaks (Earl, 2006). Movement of fluid into and through the unit is facilitated by these secondary features, as indicated by the numerous associated oil occurrences. A risk associated with this unit is cementation reducing secondary porosity. The cementation is probably at least partly related to Triassic contraction and uplift.
Siltstones and sandstones of the Arafura Group form another important reservoir in the region, hosting oil shows at both Arafura 1 and Goulburn 1. The unit has a maximum porosity and permeability of 19% and 7.83 mD at Goulburn 1, but averages 9.6% porosity with a large standard deviation (Figure 15). A significant proportion of the primary porosity has been destroyed by diagenetic effects, including silica overgrowths and carbonate cementation.
The Kulshill Group equivalent generally has poor reservoir quality, with porosities averaging 5.5%. However, the upper parts of this unit generally have better porosities (Figure 15) with a maximum of 17.7% at Tasman 1. Carbonate cements are sporadic throughout the unit but there is evidence of multiple fracture sets (such as at Chameleon 1), which could enhance the overall permeability and porosity.
Mesozoic reservoirs are important in the adjoining Bonaparte Basin, where they host a number of commercial hydrocarbon accumulations (Barrett et al, 2004; Cadman and Temple, 2005). The Money Shoal Basin also contains high quality reservoirs (Figure 16), including the Troughton Group equivalent (Jurassic), the Flamingo Group (Jurassic to Early Cretaceous) and the Bathurst Island Group (Cretaceous). Due to their distribution, Money Shoal Basin reservoirs are well positioned to receive any late hydrocarbon charge from underlying potential Palaeozoic source rocks. Sandstones of the Jurassic Troughton Group equivalent have average porosities of 8.5% with a maximum of 27% at Tasman 1 (Figure 17). Blocky fluvio-deltaic sands of the Flamingo Group have an average porosity of 18.5%, with a maximum of 32% at Tasman 1 and a range of 5-17% at Tuatara 1. There is some dolomite cementation in these rocks, but the unit also contains fractures that may help facilitate fluid movement. Where it is sandstone-rich, the Darwin Formation equivalent (eg at Kulka 1) has excellent porosity, with an average of 25%. The Bathurst Island Group also contains units with possibly excellent reservoir potential. For example, at Tuatara 1, porosities range between 13 and 33%, although no permeability data are available. The reservoir potential of basin floor sands within this unit remains untested.
Seals
Mudstones of the mid- to Late Cretaceous Bathurst Island Formation, which provide a regional seal in the Malita Graben of the Bonaparte Basin, are also present in the release area. The unit is laterally and vertically extensive and typically overlies high quality Mesozoic reservoirs. Fault breach is unlikely due to the thickness of the unit.
Other seals in the region are less homogenous. The Jurassic to Early Cretaceous section tends to be sand-dominated, but contains extensive mudstones. These include maximum flooding surfaces and abandoned channel fill and overbank deposits that could provide good intraformational seals. There is little information about potential Palaeozoic seals; however, oil shows/indications below thick Devonian fine-grained sediments at Arafura 1 and Goulburn 1 attest to the sealing capacity of this unit (Petroconsultants, 1989). Oil indications above this seal in Arafura 1 are the result of fault migration (Labutis et al, 1992; Earl, 2006). Mudstones at the top and base of the Cambro-Ordovician Goulburn Group may also provide a seal for adjacent carbonate reservoirs, and Permo-Carboniferous dolerite sills such as that intersected in Kulka 1 could provide local seals.
Timing of generation and expulsion
Moore et al (1996) concluded that oil generation and migration from potential Palaeozoic source rocks in the Goulburn Graben, where all exploration wells are located, pre-dates the Triassic structural event and thus potential trap formation. A recent geohistory study of all wells and several pseudo-well sites in the Arafura and Money Shoal basins by Struckmeyer (2006a, b) confirmed this conclusion, but demonstrated that some areas in the western Goulburn Graben could have experienced a late phase of generation and expulsion from potential Palaeozoic source rocks. For example, this includes the possibility of a minor phase of late expulsion of light oil from a Type I/II Cambrian source rock at Tuatara 1, where the lack of success is considered to be due to an absent or inadequate seal (Earl, 2006).
More significantly, the greater part of Late Cenozoic expulsion in the release area would have been from potential source rocks in the Devonian Arafura Group and the Permo-Carboniferous Kulshill Group (Figure 17), in areas where the basin experienced enough post-Triassic loading for these sediments to reach the oil window during the Late Cretaceous to Cenozoic. Modelling of wells in the western Goulburn Graben suggests that a burial depth of about 3 km is required for the upper Kulshill Group to generate and expel oil. For example, at Cobra 1A, where these conditions are met, oil generation and expulsion is modelled to have occurred during the past 10 million years (Figure 18a), whereas at Kulka 1, where these potential source rocks are present at a depth of 2.5-2.7 km, some generation may have occurred, but hydrocarbons are unlikely to have been expelled. Thus, modelling of these units is highly sensitive to the amount of Triassic erosion interpreted for any location. The lack of an accumulation at Cobra 1A has been attributed to a seal issue, rather than source and reservoir problems (Earl, 2006).
Potential source rocks of the Troughton Group (Plover Formation) are typically immature in all wells in the Goulburn Graben, apart from Tuatara 1. Here the unit reaches oil maturity and has probably generated some oil, but expulsion is unlikely to have occurred. However, at pseudo-well site G, to the west of Tuatara 1 (Figure 17), a thicker Money Shoal overburden (about 4 km) is present and modelling suggests that oil expulsion has occurred at this site during the Late Cretaceous to Recent (Figure 18b). Struckmeyer (2006b) concluded that a Plover Formation source rock could have expelled hydrocarbons in the undrilled western Goulburn Graben and in the western Money Shoal Basin towards the Calder Graben of the Bonaparte Basin, where hydrocarbon accumulations sourced from this unit are present. Both of these potential source kitchens occur within the release area. Expulsion from potential source rocks of the lower Flamingo Group probably also occurred in the Late Cenozoic to Recent in the region west of pseudo-well G.
Exploration plays and risks
Interpretation of available seismic data indicates that a variety of potential play types are present in the 2007 release area (Struckmeyer, 2006b). Palaeozoic plays include large faulted anticlines and fault blocks that could provide traps at several stratigraphic levels. Sub-unconformity plays below the Triassic regional unconformity are present in all release areas (Figure 19) within Neoproterozoic, Cambro-Ordovician, Devonian and Permo-Carboniferous strata. Diagenetic traps and other stratigraphic traps within the Cambro-Ordovician and Devonian carbonate successions are a strong possibility in this region, but are as yet untested and insufficient stratigraphic information is available to allow a detailed assessment.
The Mesozoic Money Shoal Basin section offers a variety of stratigraphic and combined structural/stratigraphic plays (Figure 19) for hydrocarbons sourced from underlying Early Palaeozoic sediments and from mature Late Palaeozoic and Mesozoic source kitchens. Onlap plays associated with the Triassic unconformity could provide numerous potential targets within Middle Jurassic fluvial sandstones and/or Late Jurassic to Early Cretaceous fluvio-deltaic clastics in lowstand, transgressive and highstand settings. Plays associated with these deposits also include drape closure over Triassic topography, fluvial channel plays, lowstand wedge plays and fault block plays. One of the main features of the Money Shoal Basin section is a Tithonian channel system that runs along the major bounding faults of the Goulburn Graben (BHP Petroleum, 1993; Miyazaki and McNeil, 1998; Barber et al, 2004) and thus could provide an important play type in the 2007 release area. The northern channel system was assessed by BHP Petroleum (1993) to be at least 225 km long and, on average, 10 km wide. Although the channel system has been unsuccessfully tested at several locations (such as Chameleon 1, Cobra 1A and Kulka 1), the feature still provides numerous untested stratigraphic/ structural traps within channel fills and associated erosional features.
The mid- to Late Cretaceous prograding shelf and contiguous slope and basin deposits provide numerous potential plays, particularly within lowstand wedge deposits such as slope fans, channel-levee systems and basin floor fans (Figures 10 and 19). Seismic data suggest that the basin floor fans are 15 to 25 km long, indicating the presence of significant prospect sizes. Tuatara 1 did not intersect fan deposits but the generally fine-grained nature of the Late Cretaceous succession suggests that good seals for any accumulations within basin floor sands exist.
A recent audit of exploration wells in the Goulburn Graben (Earl, 2006) identified timing of hydrocarbon charge, breach of structure and reservoir quality as the major reasons for the failure of wells. Thus, reservoir quality of Palaeozoic rocks and the timing of generation, expulsion and trap formation in relation to the major structuring event in the Triassic are regarded as the key risks in the southeastern release area. Risks for the younger, mostly stratigraphic plays include the presence of suitable seals.
Evidence that hydrocarbon generation and expulsion has occurred in the Money Shoal and Arafura basins is provided by oil shows/indications and gas indications in the majority of wells drilled in the region, and the presence of interstitial solid bitumens in many samples (Sherwood et al, 2006). More indirect evidence is provided by Synthetic Aperture Radar (SAR) data which revealed several anomalies across the region (Infoterra Ltd, 2003), and by the presence of a number of ALF (Airborne Laser Fluorosensor) fluors (Cowley, 2001). Seismic data show bright amplitudes at various stratigraphic levels, particularly within interpreted basin floor fans in the Bathurst Island Group (Figures 10 and 19), and these may indicate the presence of hydrocarbons.
The tectonostratigraphic and event history of the basin, together with
modelled expulsion from both Palaeozoic and Mesozoic potential source rocks
and the indirect hydrocarbon indicators described above, provide strong
cumulative evidence for the presence of active petroleum systems and potential
plays in the release area.