May 2023

Regional report: South Australia: New life in a mature basin: S.A.’s Cooper basin CCS and exploration opportunities

After 60 years of E&P activity, the Cooper basin remains Australia’s largest onshore O&G province, supplying domestic gas markets in southeastern Australia and export markets via the Gladstone LNG plant. This strategic basin has potential for further discoveries, as well as opportunities to play a key role in Australia’s energy transition through CCS projects in depleted fields.
Elinor Alexander / South Australian Department of Mines and Energy

After 60 years, the Cooper basin region remains the focus of onshore gas exploration and production activity in the state of South Australia, and it still has a strategic part to play in Australia’s national energy transition. It has produced 5.71 Tcfg since 1969, 240.4 MMbbl of oil and 88.9 MMboe of condensate since 1983, as well as 91.9 MMboe of LPG (since 1984), and it remains Australia’s largest onshore oil and gas province.  

The basin supplies domestic gas markets in New South Wales, the Australian Capital Territory, and South Australia, as well as export markets, via the Santos GLNG plant at Gladstone. Liquids are produced for export at Port Bonython. A total of 5,090 km of pipeline radiates out from the Moomba Gas Processing Plant, Fig. 1. 

Fig. 1. Cooper basin location, infrastructure and current tenements. Image: (source forthcoming)
Fig. 1. Cooper basin location, infrastructure and current tenements. Image: (source forthcoming)


The Cooper basin is a Late Carboniferous to Middle Triassic non-marine basin, located in the desert region of northeastern South Australia and southwestern Queensland. It overlies the Cambro-Ordovician Warburton basin and is overlain by the Jurassic-Cretaceous Eromanga basin. Gas and oil are produced from multiple formations in the Cooper basin, and oil is produced from multiple formations in the Eromanga basin.  

Unconventional gas plays include tight gas accumulations and the significant, but as yet uneconomic, basin-centered gas in deep troughs. Deep, dry coal seam gas plays, in the extensive and thick Permian coal measures, are currently being explored. As well as oil and gas plays, the basin has significant potential for underground storage of carbon dioxide, building on its long history of natural gas and ethane storage in depleted gas reservoirs. 

Exploration in the South Australian Cooper basin kicked off in 1954, when Santos Ltd. (South Australian and Northern Territory Oil Search) was granted exploration licences. Texas-based Delhi-Taylor Oil Corp. entered into a JV with Santos, which progressed exploration. Since then, exploration and development have taken place over a number of phases, driven by market demand for gas, the global oil price and acreage turnover.  

The first phase followed the discovery of gas at Gidgealpa, in 1963. By 1969, gas from the Cooper basin was piped 790 km (491 mi) to Adelaide. This was followed by the A$1.4-billion “liquids scheme” in the early 1980s, following Eromanga basin oil discoveries and their combined development with that of liquids from the wetter gas fields. 

The most recent phase of exploration was stimulated by the turnover of South Australian Cooper basin acreage during 1999-2001, with acreage releases to smaller explorers upon expiration of the 50-year, basin-wide exploration licenses operated by the Santos Joint Venture. This changed the state’s license map and Australia’s exploration industry, through a number of “company-making” discoveries (e.g. Beach Energy and Senex Energy). Nowadays, licenses are smaller (Fig. 1), and farm-ins and acreage releases have enabled new explorers, like Gidgee Energy, Bass Oil and Armour Energy, to enter the basin over the last few years. 

Vacant acreage is only available via competitive work program bidding rounds, run by the South Australian Department for Energy and Mining (DEM), and these continue to attract high levels of interest. There have been 13 acreage releases since 1998, which have led to 46 new Petroleum Exploration Licences (PEL) and hundreds of millions of dollars’ worth of exploration activity, increased exploration success rates and new petroleum production. No Cooper basin acreage releases are planned in 2023; however, that could change if suitable acreage is relinquished by license operators. 

Although the basin is regarded as “mature” in Australia, the average well density is only one well per 23 mi2. Oil and gas production in the South Australian (SA) Cooper basin peaked in the early 1990s; however, oil output has increased in recent years, driven by the western flank play and the construction of new pipeline infrastructure.  

Cooper basin conventional oil and gas exploration and Eromanga basin oil exploration have typically focused on four-way dip closed anticlines. And 3D seismic is proving to be an extremely useful tool for delineation of subtle oil prospects and stratigraphic traps in the Eromanga basin. New plays, such as the “Granite Wash Play” and “Deep Coal Play,” are being explored in the Cooper basin. The Warburton basin remains underexplored, despite being the target over 60 years ago.  


Three major troughs are separated by narrow, sinuous structural ridges in the SA Cooper basin. These troughs contain up to 2,500 m of Permo-Carboniferous to Triassic sedimentary fill, overlain by as much as 1,300 m of Jurassic to Tertiary cover. Figure 2 shows a schematic cross-section highlighting the stacked basins with oil and gas reservoirs and seals. 

The Late Carboniferous to Early Permian Merrimelia formation and Tirrawarra sandstone (an important gas reservoir) consist of glaciofluvial braided channels, diamictites and lacustrine shales, deposited unconformably on a glacially scoured landscape. This is overlain by extensive peat swamp and floodplain facies of the Patchawarra formation. Two lacustrine shale units (Murteree and Roseneath shales), with intervening fluvio-deltaic sediments (Epsilon and Daralingie formations), are overlain by the Late Permian Toolachee formation peat swamp and floodplain deposits.  Late Permian to Middle Triassic Arrabury formation red beds record the Permo-Triassic mass extinction with a “coal gap.” 

The Triassic succession is overlain unconformably by extensive, non-marine Eromanga basin braided fluvial sandstones (important oil reservoirs), lacustrine siltstones and thin coals. Marine shales record the Cretaceous transgression, followed by a return to non-marine fluvial and peat swamp conditions. The Eromanga basin is overlain by the non-marine Cenozoic Lake Eyre Basin. 

Fig. 2. Schematic section showing typical petroleum traps in the Warburton, Cooper and Eromanga basins some of which are potential CCS targets. Image: (source forthcoming)
Fig. 2. Schematic section showing typical petroleum traps in the Warburton, Cooper and Eromanga basins some of which are potential CCS targets. Image: (source forthcoming)


Permian formations contain extensive and thick coals, which are the source of the majority of oil and gas reservoired within the Cooper and Eromanga basins. The Toolachee and Patchawarra formations are the thickest and richest source units, with some contribution from the Epsilon and Daralingie formations. Oils and condensates are typically medium-to-light (30–60o API) and paraffinic, with low-to-high wax contents.  

Most oils in Permian reservoirs contain significant dissolved gas and show no evidence of water washing. Gas composition is closely related to maturity and depth, with drier gas occurring toward basin depocenters, although there is strong geological control on hydrocarbon composition. There has also been some local oil generation from Eromanga basin source rocks. 

The Permian coals are characterised by a high inertinite content, and as a result, these coals contain significant macro-porosity, indicating considerable free-gas storage potential, in addition to gas storage by adsorption. These deep coals are an exploration target for some of the world’s deepest coal seam gas. 

Hydrocarbon generation from the Patchawarra formation began in the Permian within the deeper troughs, although in general, most hydrocarbons were generated in the mid-Cretaceous. 


Reservoirs are primarily fluvial, fluvio-deltaic, lacustrine shoreface and deltaic turbidite sandstones. Multi-zone, high-sinuosity, fluvial channel sandstones form the main reservoirs. Porosity and permeability vary significantly with facies and burial depth, ranging from poor to good quality. The main gas reservoirs occur primarily within the Patchawarra and Toolachee formations. Shoreface and delta distributary sands of the Epsilon and Daralingie formations are also important reservoirs. Oil is produced principally from low-sinuosity fluvial sands within the Tirrawarra sandstone and braided fluvial sandstones of the Eromanga basin, such as the Hutton sandstone. Toward the margin of the Cooper basin, oil is also produced from the Patchawarra and Merrimelia formations. 


Intraformational shale and coal form local seals for the major reservoir units. The Roseneath shale is the top seal of the Epsilon formation, and the Murteree shale seals the Patchawarra formation. A younger regional seal is provided by the Triassic Arrabury formation. Seals for Eromanga basin reservoirs are provided primarily by lacustrine shales, primarily within the Birkhead and Murta formations. 


Most Cooper basin fields comprise multiple gas pools (and/or oil), stacked in coaxial Permian-Mesozoic anticlinal and faulted, anticlinal closures, and they may occur from as low as the Tirrawarra formation to pools in the Eromanga basin, depending on the extent of regional seals. The pools in the Patchawarra, Epsilon and Toolachee often are partially stratigraphic, and successful wells are dependent on the intersection of high-sinuosity channel facies. Fracture stimulation is common practice to improve recoveries from highly variable permeability sandstones. 

Permian oil and gas have migrated into overlying Eromanga basin reservoirs, particularly on the western flank of the Cooper basin, Fig. 2. 


South Australia has a gas storage licensing regime in place and a large endowment of onshore storage reservoirs suitable for carbon capture and storage (CCS), particularly in the depleted oil and gas fields of the Cooper basin. Cooper and Eromanga basin oil fields are well-suited to CO2 enhanced oil recovery (EOR), with deep reservoirs and light oil, and they are co-located with high-CO2 gas fields. Extensive datasets are available from the department for these fields, including monthly gas production by pool, well completion reports and logs, analytical results, cores and cuttings, and 2D and 3D seismic surveys. 

The implementation of CCS will decarbonise existing emissions-intensive industries in the state and provides the opportunity to create a new industrial “hub” for competitive abatement of emissions—especially in sectors with difficult-to-abate process emissions, such as cement, steel and iron manufacturing and natural gas processing. Furthermore, CCS is enabling new technologies in the state, such as low-carbon hydrogen production from natural gas (“blue hydrogen”), EOR, bio-energy and direct air carbon capture and storage. 

On Oct. 1, 2021, the Commonwealth Government’s Clean Energy Regulator (CER) finalised and registered the Carbon Credits (Carbon Farming Initiative—Carbon Capture and Storage) Methodology Determination 2021. This CCS method will enable projects that capture greenhouse gases for permanent storage in underground geological formations to generate Australian carbon credit units under the Emissions Reduction Fund, subject to eligibility requirements. 

DEM is involved in the development and implementation of policies, licensing, international standards and leading practice regulation to facilitate CCS projects. South Australian-based Santos Ltd., operator of the Moomba gas processing plant and gas pipeline infrastructure in the Cooper basin, is proposing CCS at Moomba. FID was taken in 2021, and the first injection is planned in 2024. Santos indicates that the injection cost is less than A$30/tonne.  

The Moomba CCS project aims to permanently store, in the depleted oil and gas fields of the Cooper basin, approximately 1.7 million tonnes a year of CO2 currently vented from the Moomba gas processing plant (Fig. 3)—representing a cut of more than 7% to South Australia’s total greenhouse gas emissions. CO2 will be stored in high-quality fluvial sandstone reservoirs, in four-way dip closed anticlines, with extensive 3D seismic coverage and multiple well intersections to reduce uncertainties. CO2 storage capacity has been extrapolated from produced gas volumes.  

Fig. 3. Fig. 3 {Figure 3.jpg} The global context of the Santos Moomba CCS (modified from World Oil CCS review). Image: (source forthcoming)
Fig. 3. Fig. 3 {Figure 3.jpg} The global context of the Santos Moomba CCS (modified from World Oil CCS review). Image: (source forthcoming)

These fields have held natural gas and oil for 85 million years and can provide for safe, low-cost and permanent storage of carbon. In the long term, carbon storage in the Cooper basin could store 20 million tonnes a year, from other industrial emitters, for more than 50 years. This project could evolve into the third-biggest dedicated CCUS project in the world when operational. 

Santos has developed an Environmental Impact Report (EIR) and Statement of Environmental Objectives (SEO) to facilitate CO2 storage in subsurface geological formations of the Cooper basin in South Australia, and this can be accessed via the department’s website. To measure the effectiveness of the CO2 storage, a monitoring, reporting and verification plan will be developed for approval and subsequent public release. Construction of facility and pipeline infrastructure and drilling of injection wells are currently underway for the Moomba CCS project, with the first injection targeted in 2024. 

DEM engineers chair the Standards Australia National Mirror Committee, to contribute on the International Organization for Standardization (ISO) Technical Committee (TC) 265 for Carbon Capture Utilisation and Storage. This committee is focusing on the standardisation of design, construction, operation, environmental planning and management, risk management, quantification, monitoring and verification and related activities, in the field of CO2 capture, transportation, EOR and geological storage. 


The department is passionate about managing its archive of exploration, development and production drilling, seismic and oil and gas production data, as well as core and cutting samples submitted by license operators to meet regulatory requirements. Drilling and seismic data and reports are held confidential for two years before public release, and detailed production data for six months. Cores and cuttings are available for sampling and analysis from the department’s state-of-the-art core library. Digital data can be accessed or ordered via the online “Data Centre” on the website. 

An exciting, new, free “2Dcubed” seismic dataset is now available for download or order from the website, courtesy of TGS, with Chevron’s support. Field data from 3,855 lines of 2D seismic data, acquired between 1985 and 2012, were used. This includes reprocessed 2D seismic data, with PrSTM and PrSDMpseudo 3D volumes, over the Cooper basin. 

These datasets will continue to generate new oil and gas exploration plays and help explorers evaluate future acreage releases and farm-in deals. However, there’s a new role for these oil and gas exploration and production data in identifying, de-risking and developing CO2 storage targets. 


The right geology, together with easy access to data, policy innovation, and effective land access and regulatory and investment frameworks, are reasons why South Australia is widely regarded as a great place to do business in Australia, for upstream petroleum companies and investors. There’s potential for new plays in the Cooper, Eromanga and Warburton basins, and it is hoped that exciting new data, like the 2Dcubed package, will stimulate exploration. The Moomba CCS Project is a new direction for the basin, building on previous gas and ethane storage projects and a mountain of data. It is a potential game-changer for the SA Cooper basin and the nation. 

For more information:  

About the Authors
Elinor Alexander
South Australian Department of Mines and Energy
Elinor Alexander commenced with the South Australian Department of Mines and Energy as a geologist in 1985 after graduating from the University of Adelaide with an Honours degree in geology. Since the 1990s, she has focused on researching and marketing South Australia’s petroleum, geothermal, gas storage and, more recently, hydrogen potential, to the world to attract investment via acreage releases, new data products and research deliverables. In her role as Director of the Geoscience and Exploration Branch, Ms. Alexander leads the skilled and enthusiastic energy resources geoscience team researching prospectivity, attracting investment, managing massive datasets and company work program compliance.
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