Unconventional hydrocarbons: Australia’s old rocks prove their worth

Australia’s search for petroleum began in the onshore basins where extensive areas of Paleozoic marine sequences, some with high-quality potential source rocks, and spectacular outcrop, encouraged sporadic exploration during many decades. For these efforts, there were some rewards, including the discovery of the Mereenie oil and gas field in Ordovician clastics in the Amadeus Basin in 1963 and the Blina oil discovery in Late Devonian and Mississippian carbonates in the Canning Basin in 1981. The most prolific onshore basins, however, have proven to be the Cooper-Eromanga and Bowen-Surat where the gas and oil have been primarily sourced from Permian coal measures.

From the late 1980s, the focus of exploration shifted offshore where many large discoveries were made in Mesozoic marginal basins, which today contain more than 90% of Australia’s conventional oil and gas resources (Geoscience Australia and ABARE, 2010). Recently, the search for unconventional hydrocarbons is drawing explorers back onshore. The CSG industry has been established on the Permian and Jurassic coal measures of eastern Australia and there is recognition of the potential for shale gas, shale liquids, tight gas, and light tight oil in the Paleozoic and older basins.

Unconventional hydrocarbon resources are those that require additional technology, energy, and capital, such as hydraulic fracturing, chemical treatments (e.g. acidisation), and horizontal wells to extract the gas or oil to achieve commercial flows. The recent developments of oil sands in Canada and shale gas and shale oil in the US are examples where technological advances have facilitated exploitation of these resources. Global projections show a rapid increase in production of unconventional hydrocarbons, such that shale gas and tight oil together supply nearly a fifth of the increase in global energy demand to 2030 (BP, 2013).

The present terminology is less than perfect as geological, engineering, and commercial (non-exclusive) distinctions are used to describe the various unconventional hydrocarbon types:

Shale gas is described as natural gas that has not migrated into a reservoir rock but is still contained within the low permeability (matrix porosities of ≤10% and permeabilities of ≤0.1 mD), organic-rich (total organic carbon contents of more than 2%) source rock, which can be mudstones, siltstones, and fine-grained carbonates (Geoscience Australia and BREE, 2012).

Shale liquids are natural gas liquids (condensate) extracted from liquids-rich or wet shale gas.

Tight gas occurs within low permeability reservoir rocks, and tight oil or light tight oil is crude oil occurring within low permeability reservoir rocks.

In North America, most tight oil is not produced from shale but from low-permeability siltstones, sandstones, limestones, and dolostones associated with the shales from which the oil has been generated (Natural Resources Canada, 2012). Significant thicknesses of similar facies are associated with proven oil source rocks across Australian basins, including in the Canning and Georgina basins. The use of the term light tight oil (IEA, 2012) distinguishes this liquid hydrocarbon from shale (kerogen) oil that has been produced from thermally immature oil shales after mining and retorting.

The geology, source rock geochemistry, and petroleum systems of Australia’s onshore basins have been documented in many detailed studies by the state and NT surveys (Morton and Drexel, 1997; Carlsen and Ghori, 2005; Ahmad et al, 2013) and Geoscience Australia and its predecessors (Jackson et al, 1988; Radke, 2009).

A framework of petroleum supersystems was established based on the palaeogeographic evolution of the continent (Bradshaw, 1993) and reflected in the oil family geochemistry (Edwards and Zumberge, 2005; Geoscience Australia and GeoMark, 2002).

Two major Paleozoic petroleum supersystems—the Larapintine and Gondwanan—were identified, as well as three in the Precambrian: the Paleoproterozoic McArthur, Mesoproterozoic Urapungan, and Neoproterozoic Centralian supersystems (Bradshaw et al, 1994). Laurie (2012) has recently further subdivided and described these Precambrian petroleum systems. Despite the recovery of what was termed the oldest oil in the world from the McArthur Supersystem (Jackson et al, 1986), commercial hydrocarbon production in Australia to date has been limited to Paleozoic and younger systems.

The Larapintine Supersystem is characterised by marine facies deposited in tropical seaways and marine embayments during the Cambro-Ordovician and Devonian. Carbonates and evaporites occur in these sequences along with organic-rich marine shales and shallow water sandstones. During the Carboniferous, Australia as part of Gondwana shifted southward out of the tropics to polar latitudes, setting the stage for different depositional regimes. The resulting Gondwanan Supersystem is dominated by Permian coal measures, non-marine source rocks and fluvial and glacially-influenced clastic facies. This analysis concluded that the Larapintine Supersystem contained excellent potential source rocks, with evidence for hydrocarbon generation; however, key risks include the mis-timing of trap formation and preservation of charge and porosity.

From previous studies, Geoscience Australia has built a library of the biomarker and isotopic signatures of Australia’s oils that can aid the search for unconventional hydrocarbons. Correlations between different oils can be illustrated in a dendrogram that groups similar oils into families that reflect the framework of the petroleum supersystems (Fig. 1). The oil geochemistry reveals that the major supersystems have individual petroleum systems in Australia’s onshore basins covering a wider range of ages and facies than is presently exploited in the successful US shale gas industry. For example, three mid-Cambrian petroleum systems are recognised in the Larapintine sequences of the Georgina Basin (Boreham and Ambrose, 2007). The oldest is the Thorntonia Petroleum System comprised of hydrocarbons sourced and reservoired in the Thorntonia Limestone (Hay River Formation; Smith et al, 2013) and generated by a Type II marine kerogen. The overlying lower Arthur Creek Formation also contains Type II marine source rocks that are the focus of both shale gas and liquids exploration. The geochemistry shows that these oils originated from source rocks deposited in an evaporitic environment.

In the Canning Basin, three Larapintine petroleum systems are known, including those sourced from the G. prisca-rich Ordovician Goldwyer Formation. The Devonian Gogo Formation has generated the conventional oil produced from Blina field, and the Mississippian Laurel Formation (Fairfield Group) has sourced the oils recovered from the Lennard Shelf and is now considered to be a basin-centred gas play (tight gas) in the Fitzroy Trough (Buru, 2013).

The kerogen kinetics of the marine and lacustrine source rocks that characterised the Cambro-Ordovician and older sequences show that most oil generation would occur across a narrow temperature range (Bradshaw et al, 1994). These petroleum systems would be particularly vulnerable to the negative impact of the Devonian-Carboniferous Alice Springs Orogeny, a succession of intraplate contractional events that inverted large parts of central Australia. The orogeny was intense; deep crustal rocks were exhumed about 30 km and juxtaposed with undeformed rocks of similar age (Blewett et al, 2012). Late generation is unlikely because there are few basins in onshore Australia where Cretaceous or younger deposition was sufficiently thick to push the older basin sequences into the oil window.

Fig. 1.  Dendrogram for oils from selected onshore basins.

Despite having these cards stacked against them, some Larapintine and older petroleum systems have produced conventional oil and gas accumulations. Commercial production has occurred from Ordovician reservoirs in the Amadeus Basin (Mereenie oil and gas fields, Palm Valley gas field) and Devonian reservoirs in the Adavale (Gilmore gas field) and Canning (Blina oil field) basins, as well as from Permo-Carboniferous reservoirs in the Canning Basin in the Boundary, Lloyd, Sundown, West Kora, and West Terrace oil fields (Jonasson, 2001). Several small undeveloped gas accumulations (Bonaparte, Vienta and Waggon Creek) are also in the onshore Bonaparte Basin in Devonian-Carboniferous rocks. The undeveloped Dingo gas field in the Neoproterozoic of the Amadeus Basin is representative of the Centralian Supersystem. In addition, there are flows or significant shows from Ordovician rocks in the Canning and Georgina basins, the Cambrian of the Georgina, Amadeus and Officer basins, and the Precambrian rocks of the McArthur Basin.

With unconventional hydrocarbons as the exploration target, Australia’s Gondwanan, Larapintine, and older petroleum systems with their oil- and gas-prone source rocks require re-assessment. Exploration is broadening its targets beyond conventional accumulations preserved during hundreds of millions of years to include the assessment of their source rocks and interbedded low-porosity units.

The search for unconventional hydrocarbons in these old rocks has started in Australia, as shown by the dramatically increased uptake of acreage and the major investment in exploration programs. Shale gas and tight gas are being targeted where infrastructure is established, as in the Cooper Basin; however, the chance for liquids is the driver in the more remote basins, such as the Georgina, McArthur, and Canning basins (Fig. 2).

Fig. 2.  Major sedimentary basins with shale gas/oil potential in Australia. The shading indicates the extent of the basins and does not delineate actual shale gas/oil plays in the basin.

During the past decades, Australia has established a whole new CSG-based industry. The geology and geochemistry show that the petroleum systems support the development of unconventional hydrocarbon resources in the future. The potential to access tight oil is particularly important given Australia’s declining indigenous conventional oil production. Gas and oil from Australia’s old basins could be part of future energy supplies, although much work is needed during a sustained period to make this a reality.