South Pacific

Gas projects dominate the region

Onshore and offshore projects based on LNG exports and expanding domestic gas markets are key drivers of drilling and field development

Australia. The country is actively supporting exploration and development of its oil and gas reserves, particularly offshore Western Australia and the Northern Territory. Offshore in the Bass Strait between Victoria and Tasmania, companies are also active. An estimated 210 wells were drilled in 2001, 79 offshore; 233 are expected this year. Crude and condensate production in 2001 averaged 641,000 bpd, over 90% from offshore. Gas output was 3.7 Bcfd. The government released 42 offshore blocks for bids in early 2001, with final second-round areas open until April 2002. In 2002, 41 offshore blocks were offered, with bids to close in April 2003. Of 41 offshore wildcats and appraisals reported by Wood Mackenzie from mid-2001 through first quarter 2002, there were: 17 dry holes, 6 tight holes, 5 gas-condensate, and 13 oil wells.

   Western Australia. A major development is go-ahead for expansion of the North West Shelf Project (NWSP) to exploit gas reserves of 30 to 50 Tcf with the growing local and Asian LNG market. A fourth LNG train project at the NW Shelf Ventures (Woodside operated) facilities on Burrup Peninsula was to begin in September, with first output in mid-2004. Syntroleum also plans a 10,000-bpd gas to liquids plant on Burrup. And Methanex Australia has proposed a methanol oil plant on Burrup to utilize NWSP gas. The NWSP comprises North Rankine and Goodwyn platforms and a 40-in. trunkline. Another 80-mi, 42-in. line is planned, plus a ninth LNG carrier.

Planned/underway field developments include: 1) Woodside’s Legendre oil field, 60 mi north of Burrup; 2) Apache’s Simpson oil field in Carnarvon basin; 3) Woodside’s Echo-Yodel gas-condensate fields, 70 mi NW of Dampier; 4) Apache’s four recent offshore oil finds in Carnarvon – Double Island, Victoria, Little Sandy and Pedirka; 5) Apache’s Gibson and Plato fields offshore Carnarvon; 6) ExxonMobil’s and Phillips’ Perseus and Athena gas fields, as part of the NWSP project; and 7) Agip’s Woolybutt oil field off Barrow Island.

Onshore exploration in Western Australia continued active. Seventeen onshore wells were planned, with eight in Perth basin, six in Canning basin and three in Carnarvon basin; 16 onshore applications were received in a licensing round.

   Other areas. Offshore Victoria, OMV will develop Patricia Baleen gas field in Gippsland basin in 2002 with two subsea wells and a 24-mi pipeline. In Otway basin, Woodside’s recent Thylacine and Geographe gas discoveries, plus the undeveloped La Bella and Minerva fields, give the basin promise as a major gas producer. ExxonMobil / BHP Billiton approved a 29-mi pipeline from Bream A to onshore, the fourth line from Bass Strait to Victoria. The company reported the first major gas find in Gippsland basin with the East Pilchard-1.

Offshore Tasmania in the Bass Strait, Australian Worldwide Exploration (AWE) / Origin / CalEnergy partners say Yolla development is key to the $400-million BassGas project, which will move gas / liquids to Victoria near Kilcunda. A platform at Yolla will allow tie-in of White Ibis field and future discoveries. Elsewhere in Tasmania, Great South Land Minerals plans an active onshore exploration program.

In Queensland, Santos was active drilling exploration wells in Cooper / Euromanga basin, with a notable gas discovery in SW Queensland. Drilling was to increase to some 60 wells in the sate last year. New South Wales officials say 12 onshore wells were drilled in 2001 and six onshore wells are expected this year. And the state of South Australia says 44 onshore wells, mostly gas, will be drilled this year, compared to 57 in 2001. The state reported 139 producing oil wells and 470 gas producers last year.

The offshore Northern Territory was active in 2001, with 11 wells drilled; 15 are planned this year. Eni found a new gas field with its Blacktip-1, 180 mi SW of Darwin. In May 2001, six new blocks were offered in the Timor Sea, with closing in October. Shell has proposed its floating LNG (FLNG) concept to develop Greater Sunrise gas fields in Timor Sea. And Methanol Australia has proposed an offshore methanol plant on shallow Tassie Shoal near the Evans Shoal gas field in the Timor Sea, some 150 mi NNW of Darwin. OMV plans to use an FPSO to test its Audacious field.

JPDA. In the Joint Petroleum Development Area, formerly known as ZOCA, the largest project is the Phillips-led Bayu-Undan development. The first-phase would produce wet gas, separate gas liquids and reinject the dry gas. Liquids would be marketed by tanker. Reportedly, the field will require 26 wells. First liquids are expected in 2004; engineering work is underway. The field contains an estimated 3.4 Tcf gas and 400 MMbbl gas liquids. A proposed gas pipeline to Darwin has been indefinitely postponed, as are plans for liquefying the gas offshore.

Onshore New Zealand’s Taranaki basin, Preussag Energie, Indo-Pacific Energy and other partners drilled an apparent oil discovery. The firms this year re-entered the Huinga 1 well and drilled the Huinga 1B deviation 1,600 ft, to a depth beyond 14,000 ft. The well is now on a long-term test. (Photo courtesy of Indo-Pacific Energy)

New Zealand. The two-island nation surrounded by major sedimentary basins is underdeveloped regarding its oil/gas resources. Total production reported by Crown Minerals averaged 36,000 bpd oil and condensate, and 566 MMcfd gas in 2000. Eight fields had notable production, paced by Shell’s offshore Maui field, which produces about 80% of the oil and over 70% of the gas. Taranaki basin is the most active; the East Coast basin on/off North Island, and Canterbury basin in the east of South Island are also active. Only 25 wells were drilled in 2001, and 24 are scheduled this year in Taranaki and East Coast basins. Crown Minerals expects three bidding rounds in 2002; in April it offered 20 onshore and six offshore Taranaki blocks, with an offshore offer in mid-year for Canterbury basin. Deepwater Taranaki blocks are reportedly to be offered in 2003. In 2000, 58 permits were active, the most since 1974.

Several significant discoveries were made in 2001 and early 2002, most leading to early developments. In March 2001, Shell bought Fletcher Challenge Energy’s assets, giving it majority interest in Maui field. Shell drilled the Pohokura South-1, South-2 and North wells on and offshore (from land) to prove the near-shore gas-condensate field, to come on in 2005. Shell also brought Mangahewa gas field onstream. Offshore, 10 mi south of Maui, Shell Todd Oil Services will likely develop Maari field. Onshore Rimu in southern Taranaki was a 1999 oil/gas discovery by Swift Energy; with three more appraisals, production is expected this year.

Indo-Pacific is producing Goldie oil field onshore near Ngatoro field, after drilling two wells. Swift found oil in Kauri field near Rimu. Kauri-A1 and more wells are planned. Other discoveries in Taranaki onshore include: Indo-Pacific’s Kahili-1; and Bligh’s Makino 1 and Huinga-1B. Three appraisals in East Coast basin onshore included Westech’s Kauhauroa-4B and Tuhara-1B, and Indo-Pacific’s Waingaromia-2.

Papua New Guinea. Crude and condensate production averaged 67,800 bpd in 2001, plus 332 MMcfd gas. A large percentage of the crude is exported. The low level of drilling reflects the absence of a commercial discovery since Moran field in 1996. Four onshore oil wells were drilled last year; four are expected in 2002. No offshore activity is planned since two dusters were drilled in shallow water in 2000, after which, Oil Search relinquished its license. The country has five major basins, still not fully explored; most exploration activities are in Papuan basin.

Two exploration wells in early 2002 were Orogen Minerals’ Saunders-1X near the SE tip of Gobe; and ExxonMobil’s Bakari-1 dry-hole wildcat in PPL138 east of Moran field. In January, Orogen merged with Oil Search (the new name).

The biggest activity in PNG is related to the proposed $3.5 billion project to lay a 2,000-mi-long pipeline from the Hides / Kutubu / Gobe area, south across the Gulf of Papua to Bamaga, Queensland, then SE to Gladstone, 290 mi NNW of Brisbane. ExxonMobil is the new project operator, replacing Chevron. Aggregated fields so far include Hides, Kutubu, Gobe and Moran.

In March, a conditional agreement was reached for gas sales to New South Wales-based Australian Gas Light (AGL). New links in the system were also considered to the Moomba gas processing hub. And in February 2002, the government signed an MOU on terms and conditions for the project.