CAPITAL: Canberra
MONETARY UNIT: Dollar
REFINING CAPACITY: 812,350 b/cd
OIL PRODUCTION: 5343,900 b/d
OIL RESERVES: 2.9 billion bbl
GAS RESERVES: 44.6 tcf
Offshore operators in 1999 launched a program to promote sales in response to the depressed market for Australian liquefied natural gas.
Woodside Petroleum Ltd., Shell Co. of Australia Ltd., BHP Petroleum Pty. Ltd., Chevron Corp., BP Developments Ltd., and Japan Australia LNG Pty. Ltd. formed the marketing consortium Australia LNG (ALNG) in an effort to lure customers outside Japan, the main buyer of Australian LNG. The six companies were participants in the North West Shelf LNG project off Western Australia.
Texaco Inc. unit Texas Corp. and Mobil Exploration & Producing Australia Pty. Ltd., both in the Gorgon LNG project (with Chevron and Shell), declined to join. They said ALNG would limit their ability to approach customers directly. The ALNG companies own most of more than 100 tcf of undeveloped gas reserves in fields off northern and western Australia. They said the best way to sell Australian LNG was to market it under a single brand name, with the support of all present and future LNG producers. Companies involved in three or four potential Australian projects had been competing for customers in Japan, China, South Korea, Taiwan, and India.
Later, ALNG signed a tentative deal to supply up to 4 million tonnes/year of LNG starting in 2003 to Tuntex Gas Corp., Taiwan. Negotiations continued on commercial and technical terms for the delivery, regasification, and sale of LNG to Taiwanese power stations and industrial customers.
ALNG hoped to secure further LNG sales to Tuntex, as the Taiwan company bid to supply gas to a new power station in northern Taiwan.
North West Shelf
Development of North and South Legendre oil fields on the North West Shelf was announced in 1999, nearly 30 years after Legendre North was opened. Owners of the joint venture were operator Woodside Energy Ltd. and Melbourne 45.94% each, Apache Energy Ltd. 31.5%, and Santos Ltd. and Adelaide 22.56%. The fields lie in 45-60 m of water 60 miles north of the Burrup Peninsula and 20 miles southeast of Wanaea-Cossack oil fields. Proved and probable reserves were estimated at more than 40 million bbl. Discovered in 1968, the reservoir was judged too small to be economic. A successful appraisal well was drilled in 1997, and the following year the Legendre South 1 well found oil in a nearby structure. The development would require four horizontal production wells: three in Legendre North and one in Legendre South. A directionally drilled gas reinjection well would be connected to a mobile offshore production unit.
Oil would flow into a dedicated floating storage and offtake vessel or directly into an export tanker. Between the Wandoo oil field and the Legendre field development, Apache Energy Ltd.`s Sage 1 wildcat tested 48.5°-gravity oil. The highest flow rate was 2,155 b/d through a 32/64-in. choke at 522 psi flowing wellhead pressure from Saffron sand.
Elsewhere, participants in the proposed $8 billion (Australian) Gorgon gas project in the Carnarvon basin off Western Australia announced proved gas reserves of 13.8 tcf in five fields: Gorgon, Chrysaor, Dionysus, West Tryal Rocks, and Spar.
The companies said the Gorgon area might have proved plus probable reserves of 17.6 tcf, while possible reserves could push the figure to 21.5 tcf. An LNG export project was in the planning stage.
The West Australian Petroleum Pty. Ltd. (WAPET) consortium had a gas discovery on the North West Shelf, the Geryon 1, drilled to 3,515 m in 1,232 m of water. It found 113 net ft of gas pay in three reservoirs.
In the same permit area, WA-267-P, WAPET struck gas with Orthrus 1, drilled to 3,570 m TD in 1,200 m of water. It cut a net gas zone of 53 m. Both wells were about 30 km from Gorgon gas field. More drilling was planned in 2000.
Lease owners were Chevron Asiatic Ltd., Texaco Oil Development Co., and Shell Development (Australia) Pty. Ltd., 25% each, and Mobil Australia Resources Co. Pty. Ltd. and BP Australia (Alpha) Ltd., 12.5% each. Woodside, operator of the North West Shelf Joint Venture, resumed production from the Cossack Pioneer floating production, storage, and offloading vessel at the Wanaea and Cossack oil fields after retrofitting the vessel.
Equal partners in the venture were Woodside, BHP, BP, Chevron Asiatic Ltd., Japan Australia LNG (MIMI) Pty. Ltd., and Shell. Apache had an oil and gas discovery on License TL/1 in the Carnarvon basin. The North Gipsy 1 flowed 5,940 b/d of 44.9°-gravity oil with 1,065 psi flowing tubing head pressure through a 56/64-in. choke. The well cut a 63-ft interval at 7,336-7,399 ft in Triassic Brigadier sand.
Apache said the Gipsy-Rose-Lee complex might be developed. Partners were Apache 68.5%, Kuwait Foreign Petroleum Exploration Co. 19.3%, and Tap Oil 12.2%. Apache found oil with its Nasutus 1 well on Permit 409 in the Carnarvon basin. It flowed 1,595 b/d of 20.6°-gravity oil through a 1/2-in. choke with 486 psi flowing tubing pressure. The tested interval was 2,195-2,208 ft in Flacourt sand. Apache had 50% and OMV AG 50%.
Timor Sea
Development was approved for the $1.4 billion Bayu-Undan liquids project in the Timor Gap.
Operator Phillips Petroleum Pty. Ltd. and partners planned first production in 2004. The field lies in 240 ft of water in the Zone of Cooperation Area (ZOCA) between Australia and Indonesia. The two nations signed the Timor Gap Treaty in 1989, establishing a framework for exploration and development in the area. The newly independent East Timor was expected to ratify it.
Phillips discovered the field in 1995, and BHP Petroleum Pty. Ltd. extended it that same year. Nine successful appraisal wells were drilled. The field was unitized, but in April 1999, BHP sold its share to Phillips after a disagreement about development. The project was to involve producing gas, separating and exporting the condensate and LPG, and reinjecting the lean gas. The facilities were being designed to process 1.1 bcfd of raw gas and extract 110,000 b/d of condensate and LPG. The liquids would be stored in a floating production, storage, and offloading vessel and offloaded to shuttle tankers.
A possible second phase would build a pipeline to move the lean gas to Darwin for domestic use and LNG exports.
Owners were Phillips with 50.3%, Santos Ltd. 11.8%, Inpex 11.7%, Kerr-McGee Corp. 11.2%, Petroz NL 8.3%, and British-Borneo PLC 6.7%. Santos decided not to participate in the liquids-recovery phase.
Meanwhile, Woodside started up Laminaria-Corallina fields, using a floating production, storage, and offloading vessel. Output was 140,000 b/d.
Corallina owners were Woodside with 50% and BHP Petroleum (North West Shelf) Pty. Ltd. and Shell Development (Australia) Pty. Ltd. 25% each. Laminaria owners were Woodside 44.9%, BHP 32.6%, and Shell 22.5%. Proven reserves in Laminaria and Corallina were estimated at 137 million bbl. The combined field had a 12-year life span. BHP and Canadian Occidental Petroleum Ltd. (with 50% each) developed nearby Buffalo field using a floating production, storage, and offloading vessel. It was producing 40,000 b/d. Woodside and Shell said a $10 billion domestic gas and LNG export project, Northern Australia Gas Venture (NAGV), based on gas from the Sunrise/Troubadour/Evans Shoal fields, was technically feasible but customers were lacking.
The NAGV proposal included development of the Sunrise group fields and a 490-km pipeline to shore processing facilities to be built near Darwin. The feasibility study was based on the potential for a two-train processing facility producing 7.5 million tonnes/year of LNG and 400 MMcfd of domestic sales gas.
South Australia
BHP was moving toward a $150-200 million development of Minerva gas field in the Otway basin off western Victoria.
The field, with proven reserves of 222.4 bcf, is 12 km off Port Campbell, an area known for tourist attractions such as the Twelve Apostles rock formations. The development would use subsea facilities plus a pipeline to shore and a gas plant distant from housing and tourist locations.
Associated with the project, BHP launched a feasibility study for a $550 million urea fertilizer plant at Lara, about 50 km west of Melbourne, with fertilizer company Incitec Ltd. BHP was negotiating with the Victorian state-owned Transmission Pipelines of Australia (TPA) for access to the 144-km southwest gas pipeline under construction between Port Campbell and Lara.
The 186 MMcfd line linked an underground gas storage project to the main Victorian gas grid. BHP needed a further 140 MMcfd of pipeline capacity to carry Minerva gas.
Santos agreed to sell gas to Gascor Pty. Ltd., owned by Victoria state, from its Fenton Creek and Mylor fields. The deal was for 9.95 bcf from June 1999 to January 2004. The Otway basin fields started up in June 1999.
Santos extended Meranji field in the Cooper-Eromanga basin 1.5 km east with the Meranji East 1, which cut 15 m of gas pay in Permian mid-Patchawarra. It was expected to flow 2-4 MMcfd when brought on stream in 2000.
Interests were Santos 59.75%, Delhi Petroleum Pty. Ltd. 20.21%, Boral Energy Resources Ltd. 13.19%, Novus Australia Resources Ltd. 4.75%, and Cultus Petroleum NL, 2.1%. Santos found gas 7 km southwest of Moonanga field in the Cooper-Eromanga basin. The Raven 1 flowed 9 MMcfd and 165 b/d of 56°-gravity condensate through a 1/2-in. choke from 2,622-2,632 m.
Owners were Santos 59.75%, Delhi 20.21%, Boral 13.19%, Gulf Australia Resources Ltd. 4.75%, and Cultus 2.1%.
Woodside Petroleum acquired 10% of Kipper field and 23.5% of Basker-Manta-Gummy fields in the offshore Gippsland basin from Australian Worldwide Exploration NL for $18 million. Kipper was earmarked for development to supplement gas supplies from Bass Strait fields.
AWE planned to build a pipeline to take the gas to a processing plant to be built near Orbost. Esso Australia Ltd. began production from Blackback field in Bass Strait. Output was 18,000 b/d from three wells. The field was in 400 m of water and held 18 million bbl of oil.
Longford aftermath
A royal commission investigating a 1998 explosion and fire at the Longford gas processing plant in Victoria state blamed operator Esso Australia Ltd. Esso and BHP Petroleum Pty. Ltd. were partners in the gas plant and the Bass Strait fields that feed it. The explosion and fire killed two workers and injured several others. It cut off gas supplies to Victoria state for 2 weeks in late September 1998.
The commission, which heard 53 days of testimony, said Esso did not train operators and supervisors adequately and lacked firm operating and safety procedures. It also cited Esso`s reduction in supervision at the plant, failure to conduct a crucial hazard study, and a desire to cut costs. The report said an explosion in a heat exchanger occurred after lean oil circulation pumps were off line several hours, allowing the cold liquid from absorbers to chill the vessels to extremely low temperatures. Reintroduction of hot oil into the exchanger caused it to rupture and release 25 tonnes of hydrocarbon vapors, which then ignited. The commission recommended Esso reexamine Longford for potential hazards and demonstrate its hazard training and techniques are adequate.
It urged that a government authority be created to administer safety audits for all major-hazard facilities in Victoria. The state government said it would consider that.
Meanwhile, a $1 billion class-action lawsuit was pending against Esso. The suit would allow businesses to claim losses and individuals that lost work to claim wages. Trial was expected to begin in 2000 and last 2 years.
In a legal counterattack, Esso Australia Ltd. sued the state of Victoria and its gas companies for depending on it for supplies. It said they failed to heed Esso`s warnings to acquire alternative supplies.
Onshore
Boral Ltd. made a gas discovery in the Denison trough, in southeast Queensland, Australia. During open hole tests, the Yandina 2 well, about 30 km north of Rolleston, flowed 9.5 MMcfd of gas.
A gas pipeline connects the Denison trough region to Gladstone and Rockhampton on Queensland`s central east coast. Full production was delayed at the Stuart oil shale project at Gladstone.
Suncor Energy Inc., Southern Pacific Petroleum NL, and Central Pacific Minerals NL were partners in the $250 million plant. Suncor owned half and the other two firms had 25% each.
Testing of the plant was halted in October 1999 when equipment malfunctioned, releasing dust and hydrocarbon vapors. In a subsequent run, the plant produced oil and other hydrocarbons at 60% of design capacity but nearby residents complained of noxious emissions.
The plant was near more than 25 billion bbl of shale reserves, 10 times Australia`s conventional oil reserves.
Transfield Pty. Ltd. and Tri-Star Petroleum Corp. planned a $1 billion coalbed methane project in the Bowen basin of southeastern Queensland. It would tap the Comet Ridge deposit, which held 200 bcf in a 20,000 sq km area. The operator was spending $70 million to drill and develop the resource. In 2000, a $12 million, 90-km pipeline would be completed to Wallumbilla in southern Queensland, where it would connect with the Roma-Brisbane trunkline. Construction of a $225 million, 675-km line was possible to Townsville in 2001 to meet increased demand from power stations and other industries.
Boral Ltd., Sydney, signed a 20-year, $265 million contract with BP Australia to supply coalbed methane for BP`s Bulwer Island refinery at Brisbane.
The gas was to be reformed to produce synthesis gas, the hydrogen component of which would be fed to a hydrocracker being built at the refinery.
The syngas also would be used as fuel for a $75 million cogeneration plant being built as part of the refinery`s $400 million clean fuels project.
Pipelines
Texaco Australia Pty. Ltd. and energy utility group CMS Energy Corp., Dearborn, Mich., were considering a second gas pipeline along the coast of Western Australia from Onslow to Geraldton. The line, costing up to $1 billion, would parallel a portion of the existing North West Shelf Dampier-to-Bunbury gas trunkline built in the 1980s.
At Dongara, just south of Geraldton, the line would connect with the 420-km, 120 MMcfd Parmelia pipeline (formerly the West Australian Natural Gas line), which runs southward to Perth. CMS Energy owned Parmelia. The pipeline project would open a market to enable development of the Gorgon-area gas fields off Western Australia. Texaco owned 28.6% of the fields. It would carry low-quality gas to methanol, petrochemicals, and plastics plants proposed for the Burrup Peninsula as well as proposed steel projects in the Gladstone area. Also, CMS Energy was considering building a 500-Mw gas-fired power plant between Geraldton and Perth.
Duke Energy International was building a $100 million, 494-mile, 18-in. gas line from Longford, Victoria, to Sydney. Completion was due in late 2000.
Texas Utilities Australia Pty. Ltd. acquired the Westar gas distribution utility from the Victoria government for $1.6 billion.
Texas Utilities later began building an underground gas storage facility in western Victoria. It would operate the $60 million facility, along with a 152-km gas pipeline to Geelong, west of Melbourne. The gas would be stored in depleted reservoirs in the Otway basin, beginning with Iona field.
Australian Gas Light Co. (AGL) planned to start work on a $96 million gas pipeline in central New South Wales in 2000.
The Central Ranges pipeline would include a 300-km extension from Dubbo, a spur from the main Cooper basin-Canberra-Sydney trunkline, to Tamworth in the north-central part of the state.
It would include a 1,000-km distribution system serving nine other demand areas. The project was slated for completion in 2 years.
Southern Cross Pipelines Australia acquired Normandy Pipelines Ltd.`s 25.49% interest in the Goldfields Gas Transmission pipeline in Western Australia for $147 million, bringing its interest to 88.16%.
Epic Energy was considering a $300 million project in southern Western Australia, extending its $2.4 billion Dampier-to-Bunbury gas trunkline with a line to Albany on the southern coast and then possibly on to Raventhorpe and Esperence farther east.
Natural gas
Australian Gas Association said consumption of natural gas would double over the next 15 years, making the fuel Australia`s second largest source of energy behind coal.
It said the share of gas in total energy use would increase to 22% by 2005 from 17.7% in 1999 and rise to as much as 28% by 2014-15.
The association said a third of the growth in gas demand by 2015 would come in Queensland, Australia`s third most populous state, where gas would compete with abundant coal reserves as a fuel for electricity generation.
Much of the rest of the expected increase would come in Western Australia, accounting for 26.8%, and New South Wales, the most populous state, at 17.7%.
Australia had three major gas producing regions: Bass Strait off the coast of Victoria state, the North West Shelf, and the onshore Cooper basin in South Australia and Queensland states. More supplies might come from Papua New Guinea and from the Timor Sea.
Australia had 8% of world LNG output. Most went to Japan from the $12 million North West Shelf Project.
The Australian Pipeline Industry Association said development of gas pipelines might be restrained by slow governmental approval, slim returns, and lower tax incentives. More than $6 billion in pipeline projects were in planning stages.
In 1999 the Australian Competition and Consumer Commission limited the weighted average cost of capital used in setting returns for a pipeline to 7.5%. The pipeline group said that was too low, given the risk of developing pipelines without guaranteed markets.
Refining policy
A federal report warned that the $25 billion Australian oil refining industry could be crippled if restructuring was not allowed.
The Downstream Petroleum Products Action Agenda report, developed with the industry, said joint ventures were necessary for the survival of the refining sector, which supplied 800,000 b/d of products from eight refineries.
It said the government should also consider the impact of planned greenhouse gas policies on the industry.
The report said Australian refineries faced investments of $100-200 million to meet new clean fuel standards at a time they were struggling to compete with larger, more efficient Asian refineries.
The government replied that it would consider industry restructuring proposals case by case, although the Australian Competition and Consumer Commission (ACCC) rejected two joint venture proposals in 1999.
Refiners must produce diesel fuel with a sulfur level of 500 ppm by the end of 2002 and 50 ppm by January 2006. The industry average was 1,300 ppm in 1999.
Separately, the government withdrew a proposed downstream petroleum industry deregulation plan, after the Motor Trades Association of Australia (MTAA) objected. MTAA protested the proposed repeal of the Sites Act, which would have allowed majors to compete on equal terms with independents marketing products.
The Sites Act limited majors to owning and operating only 5% of their retail sites around the country. Franchisees operate the rest. Independent retailers can own and operate an unlimited number of outlets.
The Australian Institute of Petroleum had backed the reform package. It said the majors had offered substantial concessions to independents, including access to competitively priced fuel. Afterwards, Caltex Australia formed a task force to consider selling its 1,300 franchise sites, which were 31% of Australia`s retail outlets, and becoming strictly a wholesaler.
Processing activity
Mobil Oil Australia dropped plans for a refining joint venture with Shell Australia Ltd. It explained that talks with ACCC showed "the approval process for the joint venture would be protracted and uncertain."
Later, Shell said it would close its Clyde refinery in Sydney by 2006. The 160,000-b/d Clyde refinery produced about 40% of of the fuel used in Sydney. Shell ordered a study of its existing and future manufacturing and supply arrangements in New South Wales. Also, Caltex Australia Ltd. and BP Australia Petroleum Ltd. dropped joint venture talks.
BP Amoco PLC and Caltex Australia Ltd. planned a joint venture to blend, package, and warehouse lubricants. It would include three blending plants (in Queensland, Western Australia, and Victoria) and would allow BP Amoco to close its Spotswood, Victoria, plant.
BP Australia agreed to plant 300 hectares of trees in Western Australia in a program to offset some of the CO2 emissions it produced at its Kwinana refinery, south of Perth. Cost would be $500,000.
Meanwhile, ATCO Group, Calgary, commissioned a 180-Mw cogeneration plant with Boral Energy Resources Ltd. at Adelaide in South Australia. The gas-fired plant would meet 10% of the electricity requirements of South Australia. National Power PLC, London, let a $200 million contract to build Australia`s largest gas-fired combined-cycle power plant. The 500-Mw plant was to be built at Pelican Point, near Adelaide, with the first 160 Mw of capacity due on line by November 2000. Full capacity operation was expected in April 2001.
