CAPITAL: Canberra

MONETARY UNIT: Dollar

REFINING CAPACITY: 762,115 b/cd

OIL PRODUCTION: 570,000 b/d

OIL RESERVES: 1.8 billion bbl

GAS RESERVES: 19.4 tcf

Natural gas drove Australia`s oil, gas, and petrochemical activity in 1997.

With the federal government moving toward deregulation of the gas industry, the fuel seemed certain to gain share of Australia`s energy mix. And with a series of discoveries adding to Australian gas reserves, new LNG export schemes entered planning stages for the northern part of the country.

A study by the Australian Gas Association (AGA) predicted average growth in gas demand of 3%/year through 2030. By the end of that period, the gas share of total primary energy consumed in Australia would grow to more than 28% from 18% in 1997.

The AGA study projected growth in Australian gas consumption from 744 bcf in 1995-96 to 1.98-2 tcf in 2029-30 and in LNG exports from 7.3 million metric tons to 21.5 million tons.

During 1996-2030, Australia might be able to produce 36 tcf more gas than it needed, the study said in a calculation of proved, probable, and potential supply in relation to projected demand. But moving gas to the high-demand regions of eastern Australia would require decisions about transportation capacity and sourcing, some dimensions of which would depend on policies ultimately adopted for deregulating Australian markets.

One possible source of supply for eastern Australia was Papua New Guinea. Chevron Corp. and partners in the Kutubu oil fields of Papua New Guinea`s highlands were considering a pipeline across the Torres Strait to deliver gas to Australia. The Australian part of the system would include a 2,000 km onshore pipeline from Cape York Peninsula to Townsville and Gladstone on the East Queensland coast.

In a project based on gas from the proposed pipeline, Chevron Asiatic Ltd. in 1997 let contract to Destec Energy Inc. and Stanwell Corp. Ltd. to build a 766 MW combined-cycle electric power plant near Townsville.

Other possible supplements to production in the eastern part of the country included long-range pipeline supplies from Western Australia and Northern Territory. Those regions were expected to remain able to produce much more gas than they consumed.

While AGA expected eastern Australia to need a total of 15 tcf more gas during 1996-2030 than it was likely to produce from proved and probable sources, Western Australia and Northern Territory would have a 17 tcf surplus.

LNG, petrochemical plans

Expected growth in the supply of gas relative to demand in northern and western Australia spawned plans not only for a new LNG export project but also for a large petrochemical complex.

The LNG plant, which would be built near Darwin, was under study by Woodside Petroleum Ltd. and Shell Development (Australia) Pty. Ltd. The companies in 1997 signed a letter of intent to study feasibility of a two-train plant able to produce 7.5 million metric tons/year of LNG.

They held reserves exceeding 5 tcf in the Sunrise, Troubadour, Loxton Shoals, and Evan Shoal offshore discoveries and continued exploring in the area.

Darwin also was the site of an LNG complex that was among options under consideration for dealing with gas discovered in the Timor Gap offshore area shared with Indonesia.

Separately, partners in Australia`s existing LNG export plant, the 7.5 million ton/year North West Shelf project on Burrup Peninsula, were studying a 7 million ton/year addition to capacity.

Ethane from the North West Shelf project would feed the proposed petrochemical complex in the Pilbara region of Western Australia, 1,200 km north of Perth. Dow Chemical, Shell International Chemicals Ltd., and BP Australia planned a complex centered on a 450,000 ton/year ethylene cracker, which would feed a 400,000 ton/year monoethylene glycol plant operated by Shell and Dow facilities to produce caustic acid and as much as 690,000 tons/year of ethylene dichloride.

Upstream activity

The LNG and petrochemical proposals of 1997 reflected exploratory success off northwestern Australia.

Shell Australia and equal partners BHP and Woodside disclosed a major gas discovery in the Timor Gap Zone of Cooperation between Australia and Indonesia. On a drill stem test, the Sunset-1 strike flowed 44 MMcfd of gas and 1,500 b/d of condensate through an 80/64 in. choke from pay at 2,223-2,241 m. On a test of pay at 2,194-2,155 m, the well flowed 32.5 MMcfd of gas and 910 b/d through a 72/64 in. choke.

The possible Darwin LNG scheme under discussion as an outlet for Timor Gap gas was based on the Bayu-Undan discovery straddling permits held by BHP and Phillips Petroleum Co. Phillips initially favored the Darwin LNG plant, while BHP proposed a floating condensate production center and floating LNG plant. Indonesia wanted a gas plant built on its territory. Late in 1997, the governments of Australia and Indonesia agreed to share financial benefits of development of the field and to allow the companies to base planning solely on economics.

BHP became unit operator of the Bayu-Undan discovery, which covers 130 sq miles across the two blocks. The 5 tcf field was to be developed initially as a gas-recycling project, producing condensate and liquefied petroleum gas on a floating processing, storage, and offloading facility made from a converted tanker. The partners intended to start production and exports in 2001. Later gas production was to be sent to an LNG export plant based on either BHP`s proprietary offshore technology or Phillips`s Optimized Cascade process in an onshore facility.

The Phillips group`s Bayu 5 appraisal well confirmed a southern extension of Bayu-Undan field, cutting 184 ft of gross reservoir section with the same gas-water contact found in previous wells in the field. Phillips didn`t flow-test the well, which completed the appraisal drilling program.

Elsewhere, Mobil Exploration & Producing Australia Pty. Ltd. and Phillips in 1997 reported a large gas discovery on the North West Shelf in the Athena-1 wildcat, which flowed 47.4 MMcfd of gas and 2,133 b/d of condensate on test. The strike was thought possibly to be an extension of Perseus field operated by Woodside.

Also on the North West Shelf, Mobil and partners tested light oil at a stabilized rate of 7,600 b/d in the 1 Wollybutt well between Griffin and Barrow Island oil fields.

Mobil was contemplating a floating LNG facility for undeveloped Gorgon gas field on the North West Shelf. The barge-mounted complex would be able to produce 6 million tons/year.

Onshore, Santos Group and partners reported a 77% success rate in a 2 year, $150 million gas exploration program begun in early 1996. In mid-November 1997, the group still had five wells to drill.

In 1997, the program had lifted reserves in southwestern Queensland to 2 tcf from 1.47 tcf. Santos extended the program through 1998 and indicated that further extensions were possible.

Pipelines proposed

A number of gas pipelines were in varying stages of planning as companies awaited details of Australian gas deregulation.

Victoria`s state government in 1997 approved what would be the region`s first privately owned pipeline: a 104-mile gas line by Coastal Gas Pipelines Victoria Pty. Ltd. from Carisbrook to Stawell and Horsham, with a 9 mile spur to Ararat. The pipeline`s capacity was to be 30 MMcfd.

Elsewhere, BHP and Westcoast Energy Inc. proposed to lay a pipeline from Langford, Vict., to Sydney, N.S.W. And AGL Petroleum Ltd. planned a pipeline from Wagga and Wodonga, N.S.W.

REFinery closures seen

Australian refiners, contending with an oversupply of gasoline throughout Asia, faced a shakeout as 1997 ended.

Ian Blackburne, chief executive officer of Caltex Australia, said at least two of Australia`s eight refineries would have to close.

He blamed the gasoline glut on new refineries and plant expansions in Asia, where diesel is a more important product. Australian independent marketers were able to import gasoline cheaply, making it difficult for the country`s refineries to compete.