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Sales production statistics FY 20/21
5.65 TCF sales gas (since 1970), 234.30 mmbbl oil (from 1983), 90.45 mmboe LPG (from 1984), 88.18 mmboe condensate (from 1983)
Annual Production (2020-2021)
69.65 BCF sales gas, 9.3 mmbbl oil, 1.15 mmboe LPG, 0.55 mmboe condensate
69.72 BCF sales gas, 65 840 kL condensate, Saleable CO2 Caroline 810.8 x 103 t
Annual Production (2020-2021)
1.66 BCF sales gas
Petroleum sales graphs
Raw gas production commenced from the Cooper Basin in 1969 and from the Otway Basin in 1991. A total of 160 gas fields have been discovered. Ex-field natural gas prices in South Australia are freely negotiated between buyer and seller.
The first crude oil production began in December 1982 from the Strzelecki Field. A total of 122 oil fields have been discovered and brought online since 1963.
Open file Production data are now available through PEPS South Australia including Production Details, Monthly Data and Charts. Production data can be viewed in metric or imperial units.
Table 1: South Australian petroleum production for 12 months ending 30 June 2021.
|Quantity||Value ($)||Quantity||Value ($)|
|Natural gas* (PJ)||73.86||484,605,239||87.61||522,743,974|
|Caroline 1 CO2 well (t)||-||-||-||-|
|Crude oil (kL)||1,479,331||691,841,913||1,589,042||856,728,153|
Onshore Otway Basin production for the year ending 30 June 2021 totalled 1.66 BCF sales gas, 0 kL of condensate and 0 t of carbon dioxide.
As of 30 June 2021, gas storage levels in the Cooper Basin reached 15.2 PJ.
History of petroleum production
Major gas discoveries were made at Gidgealpa in 1963 and at Moomba in 1966. These fields were estimated at the time to contain sufficient reserves to satisfy Adelaide’s projected demands until 1991 (subsequently amended to 1987 when annual demands were increased). On the basis of these discoveries, the Cooper Basin Producers signed contracts with the South Australian Gas Company (Sagasco) and with six other major users of natural gas in South Australia over the period 1966–73. The decision to generate the bulk of South Australia’s electricity from natural gas ensured the economic viability of constructing and operating the Moomba–Adelaide pipeline. Key early customers for Cooper Basin gas included the South Australian Gas Company, the Electricity Trust of South Australia (ETSA), Adelaide Cement and South Australian Portland Cement. ETSA commenced construction of the Torrens Island Power Station in 1963. It was originally to be a coal-fired plant, oil was also considered as a fuel, but in 1965 the design was converted to natural gas – this was decisive in making supply of Cooper Basin natural gas economically feasible (O’Neil 1995). The Torrens Island A Station was completed in 1967 and gas sales agreements were signed in April 1967. The Torrens Island B Station was completed in 1976.
Natural gas was first supplied to Adelaide in 1969 and is transmitted to Adelaide and country centres by pipelines originally established, operated and maintained by the Pipelines Authority of South Australia (PASA). From 1974 to 1995 PASA was responsible for the purchase of all South Australia’s gas requirements from the Cooper Basin Producers immediately downstream from the Moomba plant, and for its sale to South Australian customers. PASA was sold to Tenneco Australia (now Epic Energy) in 1995.
During 1973 an agreement was signed by the Cooper Basin Producers to supply gas to AGL for the New South Wales market from 1976 until 2006. The government of the day supported the sale, since long-term supply to Adelaide was not considered a problem and the increased production of natural gas would allow production of sufficient liquids to justify a dedicated pipeline and sufficient ethane for the establishment of a petrochemical plant. The agreement with AGL was to supply a minimum quantity of 2110 PJ (1933.8 bcf) of gas over a 25-year period to the year 2000, with priority over the next 844 PJ (773.5 bcf) of reserves, which would also extend the contract to 2006. This guaranteed gas supply to New South Wales over 30 years. Supply to South Australia, after its initial contract expired in 1987, was dependent on the whole of AGL’s requirement (2954 PJ (2707.3 bcf)) being proven.
Due to uncertainties that sufficient gas had been proven to meet the AGL contract (i.e. putting PASA supplies post-1987 in considerable doubt) and following unsuccessful negotiations with the Cooper Basin Producers for gas supplies post-1987, the Natural Gas (Interim Supply) Act was passed in late 1985, in which reserves of gas were set aside which would meet South Australia’s gas needs to 1992. This Act also cancelled the existing contracts to supply gas to PASA, thus freeing PASA to negotiate for natural gas supplies from alternative sources.
In 1987 an independent expert appointed to review the Cooper Basin gas reserves, advised that sufficient reserves existed to meet the AGL contract, with a small excess available. The Cooper Basin Producers were now free to supply customers other than AGL with gas from the main producing area (known as the Subject Area).
In early 1989 new contracts were signed between the Cooper Basin Producers and PASA which replaced the pre-existing arrangements. Under these contracts the gas was supplied from the Subject Area as well as the Murta and Patchawarra Southwest Blocks (Non-Subject Area) of PELs 5 and 6 for a period of five years. The combination of Subject Area and Non-Subject Area gas met the PASA demand from 1989 to the end of 1993. A condition of the five-year contract was that the Cooper Basin Producers would strive to add 450 PJ (412.4 bcf) of sales gas deliverable from 1991 to 2001 by the end of 1991. This condition was satisfied and in early 1992 the five-year contract was changed to a 10-year rolling contract commencing with the 1992 to 2001 period. Under the contract 95 PJ (87.1 bcf) of gas was available through 1993 with the annual contract quantity then reducing to 65 PJ (59.6 bcf). This contract expired in 2004.
A further 30 PJ (27.5 bcf) per year is now supplied from previously undeveloped fields in the South West Queensland portion of the Cooper Basin. The gas is delivered to the South Australian market via a 190 km pipeline constructed by the Producers to link the Queensland gas fields with the Moomba processing facility and Moomba to Adelaide natural gas pipeline.
Prior to the start-up of the South West Queensland gas project a small amount of Queensland gas was being processed through Moomba. A pipeline links the Epsilon Field in Queensland to the Dullingari satellite and part of the Brumby Field extends into Queensland.
In September 1994 an agreement was finalised between Santos, on behalf of the Cooper Basin Producers, and ICI (now Qenos) to supply a total of 160 PJ (146.6 bcf) of ethane from Moomba to a petrochemical plant in Botany Bay. Gorodok Pty Ltd owns the ethane pipeline that runs from Moomba to Botany Bay alongside the Moomba to Sydney Pipeline. When the South Australian Government allowed Santos to sell ethane to ICI instead of reserving it for a South Australian petrochemical plant, Santos agreed to offer 400 PJ (366.6 bcf) of additional gas to South Australian buyers. During 1996 a contract was signed with Sagasco (now Origin Energy) to purchase 180 PJ (165 bcf) of gas between 2005 and 2013. A second contract was signed with the Electricity Trust of South Australia (ETSA Corporation) to purchase 120 PJ (110 bcf) between 2006 and 2013. Earlier the contract with the government was extended for a further two years at 50 PJ (45.8 bcf) per year.
The current operator of the Torrens Island Power Station, AGL Energy, commissioned its new 210 MW Barker Inlet Power Station on 4 November 2019. It is a fast-start smart gas generator that sits alongside the Torrens Island Power Station. Two of the four gas generators at Torrens A will be progressively shut down, but the more modern four-turbine 800 MW Torrens Island B plant will continue to run as usual.
As well as supplying New South Wales markets, the Cooper Basin supplies gas to customers in South Australia and Queensland under current contracts.
Queensland has three major liquid natural gas (LNG) projects:
- Queensland Curtis LNG Project (QGC) (Queensland Gas Commission)
- Australia Pacific LNG (APLNG) (Origin)
- Gladstone Liquefied Natural Gas (GLNG) (Santos)
Late in 2014, QGC became the first company in the world to export CSG, in the form of liquid natural gas. Origin followed shortly thereafter, and the GLNG project began exporting in October 2015. In October 2015 Santos announced that Cooper Basin gas from SA began to be piped into Gladstone under a 15-year contract which will grow to taking more than half of the Cooper Basin production.
The Katnook gas field, south of Penola, was discovered in 1987 by Ultramar and was the first commercial gas discovery in the South Australian part of the Otway Basin. Follow-up drilling confirmed sufficient reserves to justify construction of a pipeline by Epic Energy to local markets in 1990. Commercial development was carried out by SAGASCO (followed by Origin Energy) who acquired Ultramar’s interests. Gas production commenced on 15 February 1991 from the Katnook Gas Plant, however production ceased in 2013.
Since the original discovery at Katnook, commercial quantities of gas were discovered in the neighbouring Haselgrove and Redman fields. More recently Beach Energy discovered deeper gas reservoirs in PACE Gas co-funded Haselgrove 3 and a new gas field at PACE Gas co-funded Dombey 1. Successful follow-up drilling at Haselgrove 4 and funding from the Commonwealth’s Gas Acceleration Program (GAP) enabled Beach to construct a new gas plant at Katnook which has been supplying gas to local markets since early 2020.
The 690 km SEA Gas Pipeline links Victorian Otway Basin gas fields to South Australian markets. Commercial gas supply from the SEA Gas Pipeline commenced on 1 January 2004. The pipeline has a current capacity of around 110 PJ/y, which at the time it commenced operation doubled gas supply capacity into South Australian gas markets. The capacity of the SEA Gas Pipeline could be increased with additional compression. The SESA Pipeline, connecting the SEA Gas Pipeline to the South East Pipeline System, was commissioned during September–October 2005 and has a design capacity of ~40 TJ/day.
Low-quality gas discovered in the Ladbroke Grove gas field found a commercial use in electricity generation at the Ladbroke Grove Power Station. Opportunities created for small power stations in the more competitive electricity market, and the strategic location of the field adjacent to the main electricity link between Adelaide and Victoria, led to Origin Energy seeing an opportunity to make the Ladbroke Grove Field commercial by using the gas to fire a 40 MW power station. Built in 1999, it began supplying power into the national electricity grid in January 2000 and now sources gas from offshore Victorian fields.
A second turbine was added in May 2000, boosting generating capacity to 80 MW. Both turbines are now powered by natural gas from Victoria via the SEA Gas and SESA Pipelines, following depletion of the Ladbroke Grove gas field. With both turbines operating, consumption of gas by the Ladbroke Grove Power Station is estimated to be around 6 PJ (5.7 bcf) per year.
Oil and gas liquids
The first Cooper Basin oil was discovered in Tirrawarra 1 in 1970. Eromanga Basin oil was discovered in 1977 with a non-commercial flow from Poolowanna 1 (Poolowanna Trough), and the first commercial oil flow was recorded from Strzelecki 3 in the following year. In order to market oil and gas liquids, the Cooper Basin Liquids Project was initiated in 1980 and completed in stages from 1982 to 1984 at a cost of $1.4 billion. The project involved the construction of a high vapour pressure liquids pipeline from Moomba to a processing plant and storage and loading facilities at Port Bonython, as well as field development, oil collection and crude stabilisation facilities at Moomba.
With the construction of the Tickalara (Qld) to Moomba Oil Pipeline by Santos in 2008, crude oil can now be transported from Queensland to Port Bonython via the Moomba to Port Bonython Liquids Line.
Shipments of crude oil and condensate commenced in 1983 and LPG handling facilities were commissioned in July 1984. The establishment of these facilities enabled the Cooper Basin Producers to bring the wet gas reservoirs into production, which further enhanced production flexibility. In 1991 condensate production from Port Bonython was replaced by a full range naphtha, which has a greater market value.
Enhanced oil recovery
A major enhanced oil recovery scheme was underway in the South Australian Cooper Basin until the end of 1996 — the ethane miscible flood in the Tirrawarra and Moorari fields. In 1986 fracture stimulation and ethane injection were commenced in the Tirrawarra reservoir of the Tirrawarra and Moorari fields. Fracture stimulation increases permeability of the reservoir and improves oil flow; it has lifted productivity by 300% in some wells. The demand for ethane to be sold as petrochemical feedstock to Qenos, and sales gas to Adelaide and AGL, has stopped the enhanced oil recovery project. The potential for further enhanced oil recovery using different techniques remains.
Approximately 7% of the total ethane entering the Moomba plant is consumed as fuel at Moomba or Port Bonython. Approximately 25% of the ethane remains in the sales gas stream after liquids extraction processing and 40–60% is used to supply Qenos. The balance is available for injection into the lower Daralingie Formation for storage.
Commercial amounts of carbon dioxide were discovered in the Otway Basin in the Caroline 1 petroleum exploration well in 1967, which was on production from 1968 – 2017. Isotopic studies indicate that the carbon dioxide originates from a volcanic source. Caroline 1 ranks as the most productive well in South Australia (in terms of value of product) with 810,842 tonnes of liquid carbon dioxide produced since 1968. The carbon dioxide was transported by road tanker to supply soft drink, firefighting, medical and other industry markets.
Otway Energy and Vintage Energy discovered a gross carbon dioxide column of at least 90 metres in the top of the Pretty Hill Sandstone in Nangwarry 1 in 2019. The well was been cased and suspended for further evaluation which is planned in early 2021.
Vintage report a recoverable CO2 booking for Nangwarry-1 of a best case 25.1 Bcf gross recoverable carbon dioxide, larger than Caroline 1 (~15 Bcf) and Boggy Creek 1 in Victoria (~14 Bcf).
Licence, drilling and seismic graphs
- Exploration licences - financial years (PDF 57KB)
- SA Exploration, appraisal and development drilling statistics - Calendar years (PDF 63KB)
- Cooper Basin success oil and gas graphs (XLSX 111 KB)
- Seismic lines - calendar years (PDF 91KB)
General well header information and open file production data are available through PEPS South Australia.