The petroleum systems of the northern Bonaparte Basin have been summarised by Barrett et al (2004), following the nomenclature proposed by Magoon and Dow (1994). They are also presented in montage format by Earl (2004).
At least two active petroleum systems have been identified and mapped in the offshore Petrel Sub-basin (Bradshaw et al, 1994; McConachie et al, 1996, Edwards et al, 1997; Kennard et al, 2000, 2002; Barrett et al, 2004; Earl, 2004; Gorter et al, 2004, 2005; Taylor, 2006):
- An oil and gas-prone early Carboniferous Milligans-Kuriyippi/Milligans(!) Petroleum System (Barrett et al, 2004) sourced from Mississippian marine mudstones within the southern Petrel Sub-basin. These mudstones were previously assigned to the Milligans Formation (Edwards et al, 1997; Kennard et al, 2000, 2002; Barrett et al, 2004), but have since been shown to belong to the underlying Langfield Group (Gorter et al, 2004, 2005; Taylor, 2006). This petroleum systems model requires that the extent of the Langfield Group and its effective source pod be mapped, and that a re-appraisal of potential source rocks in the southern Petrel Sub-basin are undertaken given the stratigraphic refinements that have occurred in recent years.
- A gas-prone Permian Hyland Bay/Keyling-Hyland Bay (.) Petroleum System (Barrett et al, 2004) in the central and northern Petrel Sub-basin sourced from pro-delta marine mudstones of the Hyland Bay Subgroup and/or shallow marine and coastal plain mudstones and coaly mudstones of the Keyling Formation. The Petrel, Tern, Penguin, Polkadot, Prometheus and Rubicon gas accumulations are most probably sourced from either the Hyland Bay Subgroup and/or Keyling Formation, whereas contributions from the Fossil Head Formation, Keyling Formation and/or older (Carboniferous) strata to the Fishburn and Blacktip gas accumulations are possible given the thickness of these sediments in the southern Petrel Sub-basin. However, the 2009 Special Acreage Release areas are at the southern limit of this petroleum system, with their prospectivity relying on the earliest Carboniferous oil and gas-prone petroleum system.
Hydrocarbon Families and Source Rocks
Hydrocarbon families and their postulated source rocks have been extensively documented within the Bonaparte Basin. Published papers and reports that detail the geochemistry of oils and source rocks from the Petrel Sub-basin include Kraus and Parker (1979), McKirdy (1987), Jefferies (1988), Edwards and Summons (1996), Edwards et al (1997, 2000), Earl (2004), Gorter et al (2004, 2005) and Edwards and Zumberge (2005).
Few geochemical analyses exist for Late Devonian source rocks in the Petrel Sub-basin, although numerous mineral exploration holes around the southern margin of the basin penetrate these sediments (Edwards and Summons, 1996). The only oil-prone source rocks sampled in the Petrel Sub-basin are from the Langfield Group in the mineral hole NBF-1002 (McKirdy, 1987; Edwards et al, 1997; Gorter et al, 2004). Where sampled from wells in the southern Petrel Sub-basin, the 'Milligans Formation' is at best gas-prone at current maturity levels (Edwards et al, 1997; Gorter et al, 2004), although further sampling and reallocation to the revised formations are required given the recent revisions to the Carboniferous stratigraphy.
Reservoirs
The most prospective reservoirs within the offshore southern Petrel Sub-basin, and for the 2009 Special Release Areas, are the Permian Keyling Formation and Treachery Formation, and the Carboniferous Kuriyippi Formation, Tanmurra Formation, Kingfisher Shale and Yow Creek Formation, as exemplified by the oil accumulations at Barnett and Turtle. The Kingfisher Shale also contains gas shows at Turtle 2. The reservoir quality of the Keyling Formation sandstone is excellent at Blacktip 1, Cambridge 1, Lacrosse 1 and Turtle 2. Reservoir quality of the Carboniferous sandstone reservoirs is typically poor due to the presence of a calcareous matrix and authigenic clays. However, porosity and permeability may be improved by extensive fracturing.
In the onshore Petrel Sub-basin, the Mississippian Milligans Formation and/or Bonaparte Formation/Langfield Group are important reservoirs for gas in Bonaparte 1, Garimala 1, Keep River 1, Ningbing 1, Vienta 1, Waggon Creek 1A and the Weaber gas accumulation, although gas is also hosted within the Devonian Ningbing Group in Vienta 1. In addition, the Kingfisher Shale, Utting Calcarenite and Waggon Creek facies of the Milligans Formation are important reservoirs for gas in Bonaparte 2.
Gas at Blacktip 1 is reservoired in sandstones of the Triassic Ascalon Formation (Mount Goodwin Subgroup), Permian Keyling, Quoin and Treachery formations, and the Carboniferous–Permian Kuriyippi Formation (Gorter et al, 2008). The Keyling Formation was the primary objective with five gas-bearing zones encountered, equating to a 339 m cumulative gross gas column that is sealed by the Fossil Head Formation (Woodside Australian Energy, 2002a; Leonard et al, 2004). The sustained, high flow rates recorded on test from the combined units within the Keyling Formation at Blacktip 1 substantially exceeded the rates achieved by any of the individual wells in the Petrel and Tern gas accumulations.
In the Petrel Deep, the Permian Cape Hay and Tern formations of the Hyland Bay Subgroup are the main reservoirs for the Petrel and Tern gas accumulations. Gas is also reservoired within the Torrens Formation (basal Hyland Bay Subgroup) at Penguin 1 and Polkadot 1. Although the Hyland Bay Subgroup was deposited across most of the southern Petrel Sub-basin, post-depositional erosion associated with the Fitzroy Movement has removed these sediments along the margins of the sub-basin, including the Berkley Platform (Lee and Gunn, 1988). Reservoir distribution and characterisation for this subgroup have been mapped in detail by Robinson and McInerney (2004). Gas at Fishburn 1 is reservoired within the latest Permian Penguin Formation.
Seals
The Permian Treachery and Fossil Head formations provide regional seals for the respective underlying Kuriyippi and Keyling formations in the southern Petrel Sub-basin. However, the Treachery Formation regional seal is partially fault-breached across the Turtle-Barnett High (Durrant et al, 1990; Colwell and Kennard, 1996). Intra-formational shaly members of the Langfield Group, Weaber Group, Treachery Formation, Keyling Formation and Mount Goodwin Subgroup may form effective local seals in a variety of trap geometries. In Turtle 2, a shelfal carbonate within the Tanmurra Formation, where not fractured, provides an excellent seal to sandstones reservoirs of the lower Tanmurra Formation. Salt diapirs are also likely to provide effective seals in a variety of settings.
In the central and outboard areas of the Petrel Sub-basin, the transgressive, thick marine shales of the Mount Goodwin Subgroup form the regional seal to the reservoirs of the Hyland Bay Subgroup. Also within the Hyland Bay Subgroup are the intraformational marine shales of the Cape Hay Formation, and the biomicritic limestones of the Dombey and Pearce formations (Colwell and Kennard, 1996; McConachie et al, 1996).
Play Types
Structural and stratigraphic traps that contain both sandstone and carbonate reservoirs have been identified at numerous stratigraphic levels in the southern Petrel Sub-basin, as shown in Figure 6 [PDF, 348KB].
The main play types within the early Carboniferous (Mississippian) petroleum system of the southern Petrel Sub-basin are drape and pinch-out plays within the Weaber Group across and against the Turtle-Barnett High, lowstand basin-floor fan sandstones within the Milligans Formation, and closures and truncations of the Langfield and older sections beneath the basal Weaber Group unconformity. Sandbar 1 targeted a basin-floor fan in the Milligans Formation, but did not encounter reservoir sands or hydrocarbons. Other play types include Tanmurra Formation reefal plays, which appear to have formed on salt-induced seafloor mounds. There are also Kulshill Group rollover anticlines on fault-blocks down-thrown against the Lacrosse Terrace.
The Fitzroy Movement is responsible for creating large-scale inversion anticlines (commonly associated with salt mobilisation), such as those drilled in the Petrel and Tern accumulations, as well as anticlines associated with faulting, for example those drilled by the Blacktip 1 (Leonard et al, 2004), Lacrosse 1 and Lesueur 1 wells.
Salt tectonics (flow, diapirism and withdrawal) has created numerous potential structural and stratigraphic petroleum traps. These features have either been identified or are thought to be present across most of the sub-basin (Edgerley and Crist, 1974; Durrant et al, 1990). Salt movement may have triggered petroleum migration and influenced migration pathways throughout the development of the Petrel Sub-basin.
Salt-related petroleum plays in the Petrel Sub-basin range from salt-core plays to salt-withdrawal basin plays. The timing of salt movements in the sub-basin varies widely, although many such salt-related traps may have formed too late with respect to hydrocarbon generation and migration. There is abundant evidence on seismic data for the presence of turbidites, basin-floor sandstones, slope-fan sandstones and coastal onlap of sandstone bodies within local depocentres over slowly migrating salt bodies (Lemon and Barnes, 1997; Miyazaki, 1997). These sandstones now constitute primary exploration objectives when found in favourable trap geometries.
Critical Risks
The key risks in the 2009 Special Release Areas are the identification of good quality reservoirs in suitable sized traps which have access to active oil and gas-prone source kitchens. Oil generation and migration has occurred within the Keep Inlet Sub-basin and Kulshill Terrace as indicated by the shows at Kulshill 1 and 2; however, the extent and adequacy of the oil charge and migration within the 2009 Special Release Areas is uncertain. Similarly, oil generation and migration has occurred within the Cambridge Trough and southern Petrel Deep, as confirmed by the oil shows at Cambridge 1, Cape Ford 1, Lacrosse 1, Lesueur 1 and Pelican Island 1. The Barnett and Turtle oil accumulations may have been sourced from either or both of these depocentres, given that there is evidence of multiple charges into these structures (Colwell and Kennard, 1996). Preservation of the oil following significant Triassic-uplift and erosion is another risk, as exemplified by the biodegradation of the Turtle and Barnett oils.
The northern parts of the 2009 Special Release Areas may be at the limit of the effective late Carboniferous–Permian gas-prone petroleum system to the north. Gas charge is confirmed at Blacktip immediately to the north, and the Fishburn, Tern, Petrel and Penguin accumulations in the central Petrel Sub-basin. The small number of suitable sized traps for economic gas accumulations provides an additional exploration risk.
Reservoir quality is variable within the 2009 Special Release Areas, with the preservation of porosity and permeability within Carboniferous reservoirs a significant risk. Sealing capacity also needs to be addressed given that oil shows occur throughout Carboniferous and Permian sediments in the wells of the southern Petrel Sub-basin. The Treachery Formation seal at Barnett and Turtle was partially breached by fault reactivation, and consequent fresh-water flushing and biodegradation of the shallow reservoirs (Colwell and Kennard, 1996).