Basin review, Markets, Offshore, Projects

Bass Strait – delivering gas for 40 years

The first successful Gippsland Basin well, East Gippsland Shelf 1 (later known as Barracouta 1), was drilled by Esso in 1964-65. The well discovered a 102.5 m gas column at a depth of 1,060 m. Following the subsequent discovery of the large Marlin gas field, the Gippsland Basin was initially perceived as a significant gas province. However, in 1967 Kingfish 1 was drilled and encountered the largest Australian oil field known to date, thereby cementing the Gippsland Basin’s place as a prolific, world class oil and gas province.

Oil and gas from the Gippsland Basin is processed at Longford. Crude oil is sent via pipeline to Westernport for export or further via pipeline to refineries at Altona and Geelong. Ethane is sent via pipeline to chemical manufacturing facilities west of Melbourne and gas is fed into the transmission system.

According to Australian Petroleum Production and Exploration Association statistics, in 2006 the average gas production from the Gippsland Basin was about 600 million cubic feet per day (MMcf/d) and represented 15 per cent of the total national conventional gas production and 27 per cent of sales gas production.

Following the privatisation and deregulation of the gas industry in 1999, gas production has grown by nearly 30 per cent. Demand is highly seasonal, with an average demand of 800 MMcf/d in wintertime and peaks of 1200 MMcf/d and about 400 MMcf/d in summertime, according to VENCorp information.

In 2005-06 gas from the Gippsland Basin accounted for more than 95 per cent of Victoria’s gas production and came from three major fields – Barracouta, Marlin and Snapper.

However, in 2005 gas production commenced from other fields. Minerva commenced production in January 2005, Casino in March 2006, BassGas in July 2006 and Otway Gas in September 2007. Together with the Iona underground gas storage facility these projects have the capacity to deliver over 600 MMcf/d.

To date, a total of 6.5 trillion cubic feet (Tcf) of gas have been produced from its developed fields. The total estimated gas-in-place in the undeveloped fields in the Gippsland Basin is about 5.9 Tcf, mostly owned by Esso/BHP Billiton.

Several Tcf of gas is also controlled by other companies including Nexus Energy in the Longtom field, Beach Petroleum and Anzon Australia in the Basker/Manta and Gummy fields, and AWE and Origin Energy in the Yolla and associated fields.

The BMG project, which recently began oil production, is set to be redeveloped to produce the large volume of gas which lies in associated fields.

A full study for the efficient recovery of all the hydrocarbons identified in the fields has been undertaken by the BMG joint venture. The gas development involves drilling of gas wells into the Manta and Gummy fields, the installation of a pipeline and a new FPSO, with a view to commence production in the first half of 2009. The Basker, Manta and Gummy fields contain best estimate contingent gas resources of 379.2 PJ.

The Kipper field has recently experienced a further step along the road to development, with a decision by the government that Esso’s proposed gas conditioning plant at Longford does not require an environmental effects statement. A final investment decision on Kipper is expected later this year.

Nexus Energy also owns interests in the Gippsland Basin, with its major project in the area being the Longtom gas/condensate field, which has best estimate contingent resources of 435 PJ of gas and 5.2 MMbbl of condensate. Gas production and processing at Longtom is estimated to start between the third quarter of 2008 and early 2009.

Onshore in the Gippsland Basin, Lakes Oil has discovered gas in tight sands in its Wombat field, which has the potential to develop into a substantial discovery.

Despite its long history of extensive exploration, many parts of the basin, especially the southern and eastern regions, are still relatively poorly understood. In the context of seemingly sustained high oil prices, the Gippsland Basin continues to attract local and international explorers.

American natural gas, crude oil and natural gas liquids company Apache is largely focused on oil exploration in the Gippsland Basin, but has some gas interests also. Tim Wall Regional Vice President – Australia and Managing Director, Apache Energy Ltd (Australia) said, “The Gippsland Basin has a tremendous amount of resource potential for us.”?

Great Artesian Oil and Gas is another company that has emphasised the potential of its Gippsland Basin petroleum assets, with Managing Director Andy Carroll recently highlighting the company’s dominant position as the largest 100 per cent holder in the Gippsland Basin and the potential of the virtually unexplored southern extent. Mr Carroll said that the assets will require a large seismic program and several wells.

Meanwhile in the nearby Bass Basin, Origin Energy’s BassGas project was officially opened in October 2006, marking the addition of a significant new source of gas supply for southeast Australia.

The BassGas project is based around the Yolla and White Ibis fields in the southern part of Bass Strait about 100 km from the Tasmanian north coast.

The project cost Origin and its joint venture partners AWE, CalEnergy, Wandoo Petroleum and Mitsui $300 million more than the expected budget, following two years of delays on the development of the project, which produces gas from the Yolla field, Bass Strait.

The project is now producing at its nameplate capacity rate with production being delivered into the Victorian gas market.

The BassGas Project will produce over 20 PJ/a of sales gas, 1 MMbbl/a of condensate and 65,000 t/a of LPG. These products are processed for sale in the onshore processing facilities at Lang Lang.

Origin said at the time that natural gas demand is predicted to more than double in Victoria over the next 20 years and the Yolla field has enough reserves to meet around 10 per cent of current demand for 15 years.

Exploration around the BassGas fields is expected to substantially increase known reserves in the area and extend the project’s life well beyond its current planned expiry.

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