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To report a serious incident to DPC, as required by Section 85(2) of the Petroleum and Geothermal Energy Act 2000, licensees should phone the serious incident report no: (08) 8463 6666.

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Petroleum exploration licences

As of October 2015, 54 Petroleum Exploration Licences (PELs) and 57 Applications (PELAs) were current over the state’s onshore petroleum prospective areas. Current onshore exploration licences are located in the productive Otway and Cooper basins (competitive tender regions where vacant acreage is gazetted for work program bidding), and frontier Officer, Arrowie, Stansbury and Arckaringa basins, and over Cainozoic basins with coal seam methane potential (where applications can be lodged).

The right to negotiate (RTN), Indigenous land use agreement (ILUA) and legislation-specific processes consistent with the Commonwealth Native Title Act 1993 have been effective in South Australia. In the case of RTN and ILUA processes to October 2015, the relevant registered native title claimants, petroleum explorers and the State Government have concluded 53 RTN agreements and 10 companies have signed up to ILUA’s with the Yandruwandha Yawarrawarrka and the Wangkangurru Yarluyandi peoples. A  successful conclusion to the current negotiations with the Dieri people will see conjunctive petroleum ILUA’s covering the whole of the SA Cooper Basin.

RTN was instigated by the Minister for Mineral Resources and Energy in relation to the four 2013 Cooper Basin acreage release blocks in 2015.  Notification advising the proposal to grant PELAs 639, 640, 641 and 642 was issued on 3 June 2015, with the notification date set at 10 June 2015 for an obligatory four month period ending 12 October 2015.  PELA 639 is wholly located within the Dieri Native Title Determination area, PELA 642 is wholly located within the Yandruwandha Yawarrawarrka Native Title Claim area, PELA 641 is located within both the Dieri and Yandruwandha Yawarrawarrka areas.  PELA 640 is located over four Native Title determination areas: Adnyamathanha People No.1 (Stage 1), Adnyamathanha People No.1 (Stage 2), Adnyamathanha People No.1 (Stage 3) and Dieri and Dieri No. 2.

All SA land access agreements cover the full cycle of petroleum activities including exploration, development
and production. Legislation-specific, RTN and ILUA processes are being instigated in other parts of the State on a priority basis, with the highest priority being given to PEL applications over play trends with the perceived highest prospectivity for material petroleum discoveries.

South Australian licence operators have been managing exploration work programs carefully during this current period of low oil prices and DSD has focused on sustaining operators and applicants during this challenging time. The most recently granted ‘over the counter’ exploration licence is PEL 650, over the Leigh Creek Coal Mine, which was granted to ARP TriEnergy Pty Ltd in November 2014.

For information on current licences and applications, please refer to the Holders of Petroleum and Geothermal Tenements in SA information sheet.

Work programs and licence documents for granted licences, including the terms prescribed in native title access agreements, are available on the Licence Register.

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Petroleum production licences

Onshore, as October 2015 there were 219 petroleum production licences (PPLs) in place over the Cooper and Otway Basins.

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Petroleum retention licences

South Australia has long-understood that industry requires recognition of life-cycle for funding, appraisal and developing resources through appropriate licences. In return for such licence security, petroleum retention licences were developed with a guaranteed level of accelerated exploration and appraisal expenditure to secure tenure for continuing five year terms provided expenditure obligations are met during such terms. A number of licensees have adopted or are seeking to have such petroleum retention licences adopted and that has resulted in a considerable expansion of areas under petroleum retention licences.

Four petroleum retention licences are current in the Otway Basin with 157 current in the Cooper Basin. A further twenty seven applications for petroleum retention licences in the Cooper Basin have been received and are expected to be granted by 2016.

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Associated activities licences for petroleum

(previously associated facilities licences)

A total of 50 associated activities licences (AALs) were current at end October 2015 under the Petroleum and Geothermal Energy Act 2000. These allow licensees to establish facilities or undertake surface surveys (e.g. seismic) in proximity to exploration, retention and production licences to provide efficiency and effectiveness for exploration and production efforts. In the main, these AALs were granted to enable the recording of full-fold seismic control within an exploration licence by recording tails of seismic lines outside these tenements.

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Gas storage licences

The new Petroleum and Geothermal Energy Act opened the State for ‘over-the-counter’ Gas Storage Exploration Licences (GSELs), while preserving storage entitlements in pre-existing petroleum licences. No royalties are levied for gas stored as an incentive for CO2 geosequestration projects. There are currently a total of 34 GSELs throughout the State with and 12 GSELs in the Cooper Basin, 12 GSELs in the Officer Basin, 4 in the Simpson Basin and 1 in the Otway Basin. Forty applications for Gas Storage Exploration Licences remain under consideration.

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Special facilities licences

Nine Special Facilities Licences (SFLs) were current at the end October 2015. A Special Facilities Licence authorises the licensee to establish and operate facilities for the purposes involving or associated with searching for a regulated substance, processing a regulated substance, producing or generating energy from a source of geothermal energy or other activities that may be relevant or incidental to searching for or processing a regulated substance, producing or storing a regulated substance or product derived from a regulated substance.

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Royalties and production

Petroleum royalty payments to the State in financial year 2014-15  were $104.4m, with estimated total product sales of $1,559m.  This brings the cumulative royalty paid since 1970 to $2.826b (2014/15 dollars) and cumulative sales to an estimated $47.260b (2014/15 dollars), Cooper Basin production is shown in Table 1. Since 1991 the average royalty paid equals 6.69% of the sales value.

Table 1Cooper Basin production statistics June 2015
Cooper Basin 
Cumulative Production 
5.30 TCF sales gas (since 1970), 186.1 mmbbl oil (from 1983), 82.0 mmboe LPG (from 1984), 80.0 mmboe condensate (from 1983) 
Cooper Basin
Annual Production (2013-2014)
57.92 BCF sales gas, 11.06 mmbbl oil, 1.38 mmboe LPG, 1.12 mmboe condensate

In 2010/11 many Cooper Basin fields were faced with flooding restrictions, however in 2011/12 fields returned to full production capacity.  In 2012/13 crude production increased over 53%, which was due to overall higher production and record sales generated from mostly crude within the Cooper Basin, (5 additional fields went online, with Western Flank flowlines operating at maximum capacity).  Production of LPG was lower, due to planned shutdown activities during the 2012/13 financial year noting sales gas and ethane production and pricing are directly influenced by sales gas commercial contract arrangements.

In 2014/15 crude, condensate and LPG production increased, while sales gas was slightly lower overall due to higher downtime (planned field and maintenance activities), when comparing to the previous financial year.

The State’s oil production trends were declining until 2002 when new technology and a resurgence in drilling activity led to discoveries along new play trends e.g. the Cooper Basin western flank. Beach Energy became the largest net oil producer in the Cooper Basin in 2013.  Gas sales peaked in 1989, were at a plateau for 10 years, and have been declining since 1998, however new plays in unconventional reservoirs such as deep coals, tight sands, lacustrine shales and composite lithology plays  in the Cooper Basin could reverse this trend.

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Petroleum drilling and seismic

The Australian Bureau of Statistics reported that petroleum exploration spending in South Australia totalled $400.1 million in the 12 months to June 2015.

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Drilling

In 2014 a record 122 wells were drilled in onshore licences under the Petroleum and Geothermal Energy Act 2000:

  • 119 petroleum drillholes in the Cooper Eromanga Basin, comprising 24 conventional petroleum exploration wells, 6 dedicated unconventional gas exploration and appraisal wells (Table 3), 20 appraisal wells and 69 development wells.
  • 2 unconventional gas exploration wells in the Otway Basin.
  • 1 unconventional gas exploration well in the Arckaringa Basin.

The South Australian Cooper – Eromanga basins have significant potential for natural gas in unconventional reservoirs, and if proven to be economic, the development of related gas plays could extend production for decades.  Prospective plays include: gas in deep coals; gas in stacked low permeability (tight) reservoirs including shale, siltstone, tight sandstones and coal; and shale gas.Contingent unconventional gas resources totalling 4.6 TCF have been identified in the South Australian Cooper Basin by the Cooper Basin Joint Venture (operated by Santos), Beach Energy and Senex Energy, approaching the total sales gas production from the Basin to date.

Explorers have accelerated appraisal of Cooper Basin unconventional gas plays (Table 3). Gas explorers have been encouraged with results from the first 34 vertical and 4 horizontal wells drilled to target natural gas in deep unconventional reservoirs in the South Australian Cooper Basin since 2010. In December 2012, Beach Energy spudded Holdfast, the first dedicated horizontal well to test shale gas deliverability in the State. Fracture stimulation and flow testing programs have also gathered pace.

Santos Ltd

Santos announced in July 2015 that exploration of the Patchawarra wet gas fairway in the SWJV (Drillseach farm-in acreage) was highly successful with seven discoveries from eight wells. The wells have been cased and suspended for future production from conventional sands and unconventional deep coal zones, selected wells will be connected and brought on production before the end of the year.

The Cooper Basin’s first stand-alone deep coal producer, Tirrawarra South 1, was successfully brought online in May and is flowing wet gas in-line. The well will provide the Joint Venture with long-term dynamic performance data from the deep coal.  Santos drilled Washington 1 targeting coals within the Toolachee, Epsilon and Patchawarra formations in August-September 2015 and followed up with a 5 stage hydraulic stimulation and flow testing in November.

Beach Energy Ltd

Beach Energy to date has drilled 5 exploration, 2 appraisal and 6 development wells in 2015  Beach has had success in their exploration program with discoveries in their Ralgnal and Stanleys wells. Appraisal drilling has been concentrated on recent western flank discoveries. The majority of the development drilling has been on Bauer field. Beach ceased drilling in their South Australian licences for a few months, recommencing work in November 2015, the company  continued to participate in Cooper Basin Joint Venture exploration and production activities

Senex Energy Ltd

Senex drilled 4 exploration, 4 appraisal and 1 development wells in Cooper Basin Permits. Senex has had success in their exploration program with discoveries in their Martlett North and Morris wells. Senex also successfully drilled Efficient 1  targeting a stratigraphic play in the Patchawarra. There are plans for hydraulic stimulation which will determine if the well was successful in the Allunga Trough. Senex reduced its FY2015 SA Cooper Basin drilling program from 26 to 13 wells in response to impacts of the lower oil price environment. Senex announced in June that they were planning their FY2016 program.

Strike Energy Ltd

PEL 96 in the southern Cooper Basin was granted in May 2009 and since then, five wells have been drilled to test the  moderate to deep Permian coals, including 3 closely spaced Klebb wells (Table 3).  Strike are currently running extended flow testing of all 3 Klebb wells.

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Geophysical and geochemical surveys

Offshore exploration permits for petroleum

Exploration in the state’s offshore basins is ramping up with major international explorers completing large seismic surveys in their EPPs and preparing to drill deep exploration wells from 2016-17.  potential for giant petroleum accumulations in the Bight Basin where recognised exploration targets are similar to those in prolific gas–oil provinces elsewhere in the world. Nine exploration permits for petroleum (EPPs) were current in federal waters adjacent to South Australia at the end October 2015. A large frontier region in the Bight Basin, S15-1, was released by the Federal Government as part of the 2015 Australian offshore bid round in May, work program bids close 21 April 2016.

BP Exploration (Alpha) Ltd was granted EPPs 37 to 40 inclusive in the Bight Basin on 14 January 2011. BP has guaranteed to undertake exploration worth about $605m with the acquisition of 11 400 km2 of 3D seismic completed in May 2012, followed by four exploration wells by June 2017. The combined secondary exploration program includes an additional six deepwater wells and 5 000 km2 of 3D seismic for a total expenditure of $832m, bringing total investment to $1.437b over six years.

Two permits (EPPs 41 and 42) in the Duntroon and Ceduna sub-basins of the Bight Basin were awarded to Bight Petroleum Pty Ltd on 7 July 2011. Bight Petroleum has proposed 768 km2 of 3D seismic and 235 km of 2D seismic in the first operational year, and one exploration well in the third operational year, with total guaranteed expenditure of $67.6 million for the combined Primary Term work program. The combined Secondary Term work program commitments for the two permits include an additional 3 wells, 2 269km2 of 3D seismic and 405km of 2D seismic for a total expenditure of $210 million. Total exploration expenditure for the two permits is approximately $278 million over 6 years.

EPP43 was awarded to Murphy Australia Oil Pty Ltd and Santos Offshore Pty Ltd on 22 October 2013. The joint venture proposed a guaranteed work program of 4,000km 2D seismic survey; 2D processing, interpretation and 3D planning with a 4,600km² 3D seismic acquisition and processing program, totalling $50 million. The secondary work program consists of 3D processing, interpretation, one exploration well and post well studies totalling $53 million.

EPPs 44 and 45 were awarded to Chevron Australia New Ventures Pty Ltd on 22 October 2013. Chevron proposed a guaranteed work program of geological and geophysical studies, 21,000 km² 3D seismic acquisition and four exploration wells, totalling $486 million. The secondary work program consists of geological and geophysical studies, 2000 km² 3D seismic acquisition, geological and geophysical studies and prospect review totalling $10 million.

Coal seam gas

Coal measures in South Australia are primarily of Permian, Triassic, Jurassic and Tertiary age, and while most known deposits have been evaluated for coal extraction potential, few have been evaluated for coal seam gas potential (CSG). The depth and maturity of the coal deposits and distance to infrastructure and markets has prevented economic exploitation of all except Leigh Creek. Over the last 20 years, coal research in the state has focused on proving up known deposits for mining and power generation, and only limited greenfield coal exploration has taken place.

Interest has been shown by a number of companies to explore for CSG in South Australia over the last five years.. Currently there are twelve PELs and six PEL applications under consideration for exploration rights to evaluate the CSG potential and/or underground coal gasification potential of South Australian coals. Known South Australian coal deposits and relevant PELs and PEL applications are located in Figure 6. The determination of some PELs is delayed pending resolution of native title land access agreements. The three companies exploring for coal seam methane and/or in situ gasification opportunities in South Australia are listed below.

Linc Energy

SAPEX Limited (a Linc Energy subsidiary) was granted PELs 117–119 and 121–124 in the Arckaringa Basin and PEL 120 over the St Vincent and Walloway Basins in September 2006. In October 2008, SAPEX Limited merged with Linc Energy Ltd which now operates the licences. Linc are also the Mining Act licensee for the Wintinna East and Weedina coal deposits. The company has more recently been focusing on an oil shale play in the Stuart Range Formation and  conventional oil plays in the Arckaringa Basin after oil shows were recorded in the Maglia 1 well.

PELs 123 and 124 were renewed by SAPEX Limited for a further 5 year term in October 2015.

Energy Exploration Limited

PELs 126 and 153 were granted to Energy Exploration Pty Ltd in April 2014 over the Lock coal and Mullaquana coal–oil shale deposits (Polda Basin).

ARP TriEnergy Pty Ltd

Granted PEL 651 located over the Leigh Creek coal field in November 2014.

For more information, contact:

Elinor Alexander
Director Geoscience & Exploration Branch
Energy Resources Division

+61 8 84633211
elinor.alexander@sa.gov.au