The following is a summary of the Oil and Gas Resources of Australia (OGRA) Report 2003 [PDF 1.8MB], an annual report which provides information and statistics on Australia's oil and gas resources.

Exploration 2003

Sixty-three offshore exploration wells were drilled in 2003, 17 wells more than in 2002 (46 wells) and four more than the number drilled in 2001 (59 wells). Offshore, 48 new-field wildcat wells and 15 extension/appraisal wells drilled resulted in six new field discoveries, including those discoveries inferred from well logs and repeat formation tests. In 2003 new-field discoveries occurred in the:

Onshore, 43 exploration wells were drilled in 2003, one well more than last year's level of 42 wells drilled. There were 31 new-field wildcat wells and 12 extension/appraisal wells drilled, resulting in 12 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 the relinquishing in 1999 of Petroleum Exploration Licenses 5 and 6 in South Australia, leading to the entry of new operators into the area. Focus continues on exploration drilling throughout the numerous production licences held in the South Australian part of the Cooper and Eromanga Basins. The drilling carried out by operators in the region during the year resulted in two oil discoveries and seven gas discoveries. Further oil and gas discoveries occurred in the Bowen and Surat Basin of Queensland at Overston 1 (gas) and Myall Creek East 1 (gas) and in the Perth Basin at Eremia 1 (oil).

In 2003, a total of 24,412 line km of 2D seismic surveys and 7554 km² of 3D seismic surveys took place in Australia. Offshore, 28 seismic surveys were carried out (27 completed) which collected 22,908 line km of 2D data and 7100 km² of 3D data. Onshore, there were 12 separate seismic surveys, which acquired 1504 line km of 2D data and 454 km² of 3D data.

Petroleum exploration expenditure in 2003 was A$755.7 million of which A$615.2 million was expended offshore and A$140.5 million onshore. Expenditure on development and production in 2003 was A$3071.2 million of which A$2394.6 million was offshore and A$676.6 million onshore.

Timor Gap Joint Petroleum Development Area (JPDA)

On 20 May 2002, the date of independence of the Democratic Republic of Timor Leste (Timor Leste), 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.

The part of the Timor Sea 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 proposed: the Bayu-Undan field and the Greater Sunrise field. The Elang Kakatua oilfield located within the JPDA has been in production for several years. These fields are of major national interest to Australia and revenue from them will support Timor Leste's future development.

The development of the JPDA Bayu-Undan field has commenced, with liquids revenue flowing in 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.

An international Unitization Agreement for the Greater Sunrise field, which straddles the edge of the JPDA and Australian territory (with 79.9 per cent in Australian jurisdiction and 20.1 per cent inside the JPDA), provides the framework for negotiations between the Australian Government and the Timor Leste Government for the field to be developed as an integrated whole.

Reserves and resources

Most (608 of 981 GL or 3.8 of 6.2 Bbbl (billion barrels)) of Australia's initial commercial crude oil reserves have been discovered in offshore Tertiary 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.

There has been an overall increase in crude oil reserves and a reduction in condensate reserves for identified fields in the year to 1 January 2004. Oil reserves increases are predominately due to the 'heavy' oil discoveries in the Carnarvon Basin. Production has been the main reason for the decline in condensate reserves, although the revision of recent gas discoveries has led to a small downward movement in gas and condensate reserves.

The world reserves totals at the end of 2002 were 193 GL or 1213 Bbbl of crude oil and 5501 Tcf (trillion cubic feet) or 155,770 BCM of gas. The notable features are Australia's increased share of world gas reserves due to recent large discoveries on the North West Shelf and gas production secured by LNG exports from the North West Shelf. At the end of 2002, Australia ranked 30^th and 13^th in oil and gas reserves and 28^th and 17^th in oil and gas production.

Development

In September 2003, the Western Australian Government approved in-principle the restricted use of Barrow Island for the development of the Gorgon area gas fields. The Gorgon gas project revolves around the establishment of a Liquefied Natural Gas facility on Barrow Island. In April 2004, ChevronTexaco Australia Pty Ltd submitted to the Government the preliminary field development for the Gorgon gas field, as a precursor to an application for a production licence.

On 15 February 2004 the first condensate production was achieved from the Bayu-Undan gas recycle phase of the project, following the successful commissioning and start-up and the first shipment of 54 ML or 340,000 bbl of condensate was completed on 30 March 2004.

The Yolla Field commenced construction in April 2003 and will be the first gas production from the Bass Basin, located in exploration permit T/RL1, 120 km offshore from Tasmania and 220 km southeast of Melbourne in a water depth of 80 metres.

ROC Oil is progressing towards the development of the Cliff Head oil field, which was discovered at the end of 2001 in the offshore Perth Basin, permit WA-286-P. The field is situated approximately 11 km off the Western Australian coastline in 16m of water.

In the Carnarvon Basin, Woodside is planning to drill additional subsea development wells into the Perseus field. The wells will be drilled in the southern and western parts of the Perseus field to drain reservoir layers not directly drained by the Perseus wells drilled from the North Rankin A platform. The first phase of this development will involve the drilling of three wells tied back to the Goodwyn A platform via a 16-inch pipeline.

In March 2003, Woodside Energy Ltd submitted the preliminary field development plan to the Government as a precursor to an application for a production licence over the Enfield oil field and the development was approved by the Woodside Board in March 2004.

The Enfield oil field is located approximately 16 km north of the northernmost part of Ningaloo Reef in exploration permit WA-271-P in the offshore Carnarvon Basin. The development comprises subsea wells tied back with flow lines to a floating production, storage and offloading facility (FPSO) of double-hulled construction, disconnectable mooring, its own propulsion system to allow it to evade tropical cyclones and a storage capacity of approximately 143,000 cubic metres (900,000 bbl). The FPSO will be positioned west of Enfield in a water depth of 550 metres. Due to the proximity of the development to the Ningaloo Reef, both produced water and surplus gas will be re-injected back into the reservoir unit.

On 9 June 2003 Woodside submitted a Preliminary Development Concept to the Government as a precursor to an application for production licences over the Geographe and Thylacine gas fields. The Geographe and Thylacine gas fields are in exploration permits VIC/P43 and T/30P respectively, about 55 and 70 km south, respectively, of Port Campbell, Victoria, in water depths of 80-100 metres. The Otway Gas Project involves the initial expenditure of A$810 million for the development of the Thylacine gas field. The Geographe gas field will be connected to the main offshore pipeline about 2-3 years after Thylacine comes into production.

In February 2004 Santos announced that expenditure had been approved for the completion by the end of 2004 of Front End Engineering and Design studies and regulatory approvals for the Casino field development. Pending a final investment decision, the first gas from the Casino field is scheduled in first quarter of 2006.

The production licences over the Mutineer and Exeter oil fields were granted. 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 metres to 160 metres. The field life is estimated at 7-12 years. It is forecast that the two fields will come off the plateau production rate of 15.9 ML/d (100,000 bbl/d) after two years of production.

In July 2003, OMV Australia submitted to the Government the preliminary field development plan for the Sole gas field, as a precursor to an application for a production licence. The Sole field is located in Retention Lease VIC/RL3 in the offshore Gippsland Basin, Victoria. The field is approximately 35 km offshore and 65 km from the existing Patricia Baleen Gas Plant. The proposed development of the Sole field consists of two subsea production wells and a new connecting pipeline and umbilical control line between the wells and the existing Patricia Baleen Gas Plant. The existing Patricia Baleen Gas Plant will be extended to accommodate additional Sole gas production. First Gas is targeted for early 2005.

Production

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.

Sufficiency

Crude oil and condensate remaining reserves in 2003 could sustain production of 33.4 GL or 210 million bbl/year for 13 years. This average production level was calculated for the period 1993 to 2003. The consumption of crude oil and condensate in 2004 could be sustained by remaining economic reserves for only 9.3 years.