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.
Department for Energy and Mining, South Australia
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.
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
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
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
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
local oil generation from Eromanga basin source rocks.
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
generation from the Patchawarra formation began in the Permian within the
deeper troughs, although in general, most hydrocarbons were generated in the
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.
CAPTURE AND STORAGE
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
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
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
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
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.
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
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. WO
For more information: www.petroleum.sa.gov.au
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.