Oil and Gas Resources of Australia - 2004
The following is a summary of the Oil and Gas Resources of Australia (OGRA) Report 2004 [PDF 2MB], an annual report which provides information and statistics on Australia's oil and gas resources.
A total of 123 exploration wells were drilled in 2004, 27 wells more than in 2003 and 33 more than 2002 (90 wells). Offshore, 27 new field wildcat wells and 16 extension/appraisal wells drilled resulted in 12 new field discoveries, including those discoveries inferred from well logs and repeat formation tests. In 2004 new field discoveries occurred in the:
Bass Basin at Trefoil (gas);
Bonaparte Basin at Katandra (oil);
Carnarvon Basin at Altostratus, Harrison, Monet and Stickle (oil), Boojum and Wheatstone (gas), Gungurru and Eskdale (oil and gas);
Gippsland Basin at Moby (gas);
Otway Basin at Martha (gas).
Onshore 80 exploration wells were drilled in 2004, more than double the number in 2004. There were 59 new-field wildcat wells drilled and 21 extension/appraisal wells drilled resulting in 34 new-field discoveries. Most of the success and activity occurred in the Cooper and Eromanga basins of South Australia and Queensland where exploration drilling continued to be driven by new operators into the area. Further oil and gas discoveries occurred in the Perth Basin in Western Australia, the Bowen and Surat basins of Queensland and the onshore Gippsland Basin. A full list of discoveries is given in Appendix C.
In 2004, a total of 24,109 line km of 2D seismic and 8719 km2 of 3D seismic were recorded in Australia. Offshore there were 25 seismic surveys carried out (23 completed) which collected 19,959 line km of 2D data and 7339 km2 of 3D data. Onshore, there were 35 separate seismic surveys carried out which acquired 4150 line km of 2D data and 1380 km2 of 3D data.
Petroleum exploration expenditure in 2004 was A$921 million of which A$663 million was expended offshore and A$258 million onshore. Expenditure on development and production in 2004 was A$4918 million of which A$3694 million was offshore and A$1223 million onshore.
On 20 May 2002, the date of Timor-Leste's independence, Australia and Timor-Leste signed the Timor Sea Treaty. This Treaty governs petroleum exploration and development in that part of the Timor Sea subject to overlapping jurisdictional claims.
The Treaty came into force on 2 April 2003 and sets the framework for joint administration by Australia and Timor-Leste of petroleum exploration and development in the Timor Sea. The Treaty sets out matters such as fiscal and administrative arrangements and importantly gives certainty to investors in the JPDA created by the Treaty.
Part of the Timor Sea is subject to overlapping territorial claims by Australia and Timor-Leste. This area contains extensive resources of oil and gas and two major petroleum development projects are underway or proposed - the Bayu-Undan Field and the Greater Sunrise Field. These fields are of major national interest to Australia, and revenue from them will support Timor-Leste's future development.
The development of the Bayu-Undan Field has commenced with liquids revenue flowing from early 2004. From 2006, gas from the field will be processed onshore in Darwin, providing employment opportunities and export revenue. Development of the Greater Sunrise Field offers substantial long term benefits for Australia with development and investment decisions to be made at a later stage.
Most (610 of 992 GL) of Australia's initial commercial crude oil reserves have been discovered in offshore Paleogene reservoirs in the Gippsland Basin. Additional major oil reserves have been discovered in the Carnarvon and Bonaparte basins. The most significant gas reserves are located in the Carnarvon, Gippsland, Browse, Bonaparte and Cooper Basins.
Despite the number of discoveries in 2004, there has been an overall decrease in crude oil and gas reserves for identified fields in the year to 1 January 2005. Condensate reserves increased over the same period.
In October 2005 Anzon Australia Limited commenced a six month extended production test from the Basker Field using the FPSO vessel, the Crystal Ocean. The test production rates from the Basker 2 appraisal well were approximately 1,431 kL/d (9 kbbl/d). The production rates are expected to rise to about 3,178 kL/d (20 kbbl/d) during peak production when the fields are fully developed in mid-2006.
In June 2005, Esso applied for a Production Licence for the Kipper gas field. Front-end engineering and design is expected to commence in the first half of 2006 while production from the field is expected to commence in 2009.
A production licence (Vic/L24) for Casino development was granted to Santos in April 2005 and development is progressing as scheduled. The development drilling phase, comprised Casino 4 and 5 wells, which were successfully drilled and completed for production. First gas is anticipated from the Casino gas project in the first quarter of 2006.
Government approval for the development of the Thylacine and Geographe gas-condensate fields was granted to Woodside in April 2004. In May 2004 the Joint Venture Partners approved development of both fields. Construction work started in early 2005 and is progressing as scheduled. The production star up is expected around mid 2006.
In early 2005 the first gas production was achieved from the Minerva gas field operated by BHP Billiton. The field is located in the Otway Basin, in VIC/L22 permit, approximately 10 km from Port Campbell in 60 m of water. The field is producing at a rate of 3.82 million m3/d (135 million scf/d) of sales gas, and up to 79.5 kL/d (500 bbl/d) of stabilised condensate.
The Yolla development has been delayed following the identification of a number of defects in the key systems of the project. Defect rectification works are continuing on the project and commissioning of the onshore plant and production from the Yolla field is expected in the first quarter of 2006.
On 23 September 2005 AED Oil Ltd submitted a Preliminary Field Development Plan (PFDP) for the Puffin oil field. The field is located in Exploration Permit AC/P22 in the Vulcan Sub-Basin. The Permit is located approximately 80 km south west of the Jabiru and Challis oil fields and approximately 25 km from the Skua oilfield.
In October 2005 INPEX Browse Ltd briefed the Government on their plans with regard to Ichthys gas and condensate field development. Currently INPEX is evaluating various developmental scenarios, targeting the initiation of commercial production after 2010.
In May 2005, Woodside submitted the final field development plan for the Angel gas field to the Government. The development drilling is planned to begin in 2007, with the platform due to be fully operational by the end of 2008.
Woodside's Enfield oil project is more than 60 per cent complete, with first oil production expected in the fourth quarter of 2006. In April 2005 the FPSO Nganhurra was launched from its floating dry dock. Topsides facilities were installed and integrated with the hull during the remainder of 2005. In March 2005 the Transocean operated semi submersible drilling rig Jack Bates started work on the drilling of 13 wells that will be needed to develop the Enfield oil discovery. This drilling campaign will take about 12 months to complete.
The Mutineer-Exeter fields commenced production on 29 March 2005. Production rates during the second quarter 2005 averaged 11,447 kL/d (72 kbbl/d). The fields are located in the northern part of the Dampier Sub-basin of the Carnarvon Basin in Western Australia in water depths ranging from 140 to 160 metres. The fields are approximately 150 km north of the Dampier and 40 km north of the Cossack Pioneer FPSO.
In July 2005 ChevronTexaco Australia Pty Ltd announced its decision to move the Greater Gorgon development into the Front End Engineering and Design (FEED) phase. The FEED scope includes the establishment of a two train (10 mtpa) LNG facility and domestic gas plant on Barrow Island.
In June 2005, Mobil Exploration and Producing Australia Pty Ltd submitted to the Government the preliminary field development plan for the Jansz-Io gas field, as a precursor to an application for a Production Licence.
Production from the John Brooks gas field commenced in September 2005, producing at an initial flow rate of approximately 1.69-2.27 million m3/d (60-80 million scf/d). John Brooks is located some 60 km northwest of Varanus Island.
In December 2004 Woodside's 'Perseus over Goodwyn' project (PoG) received final investment approval. The project first phase comprises of three subsea wells tied back to the Goodwyn-A platform via a 16 inch diameter pipeline. Current plans also incorporate development of the liquids rich Searipple reservoir by one Searipple sub-sea well tied back to Goodwyn-A platform via the Perseus subsea pipeline. The PoG project is scheduled for start-up in the first quarter of 2007.
In November 2005 BHP Billiton and Woodside Energy have approved the A$813.67 million development of Stybarrow oil field. The Stybarrow oil field is located 56 km northwest of Exmouth offshore Western Australia with the Eskdale oil and gas field another 12 km further northwest in the Exmouth Sub-basin of the Southern Carnarvon Basin. Stybarrow will be Australia's deepest-ever oil development.
In December 2005 Woodside provided advance notice to the Government of the WA-28-L Joint Venture's plan for submission of the preliminary Vincent Field Development Plan. Vincent is covered by the Enfield Production Licence (WA-28-L). The Joint Venture final investment decision is expected in March 2006. The current plan for first oil production from the Vincent discovery is in 2008.
The Cliff Head oil field development is in progress and the first production is expected in the first quarter of 2006 at initial production oil rates of 2,544 kL/d to 3,816 kL/d (16 kbbl/d to 24 kbbl/d).
Estimates by Geoscience Australia of future crude oil plus condensate production suggest production in 2005 at between 78.0 ML/d or 490,700 bbl/d and 107.3 ML/d or 674,700 bbl/d and a decline to between about 25.0 ML/d or 157,000 bbl/d and 54.2 ML/d or 341,000 bbl/d by 2025.
Crude oil and condensate remaining economic demonstrated resources at the end of 2004 could sustain production of 34.0 GL/year for 14 years. This average production level was calculated for the period 1995 to 2004. The projected consumption of crude oil and condensate in 2005 could be sustained by remaining economic demonstrated resources for 9.8 years.
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