MONETARY UNIT: DOLLAR
REFINING CAPACITY: 846,500 B/CD
OIL PRODUCTION: 720,000 B/D
OIL RESERVES: 2.9 BILLION BBL
GAS RESERVES: 44.6 tcf
The Australian government in 2000 agreed to exclude liquefied natural gas from the nation's greenhouse gas reduction measures, relieving concerns of the Australian petroleum industry.
It also postponed plans to create a greenhouse gas emissions-trading program until other nations did the same.
Australian producers feared they would be unable to compete with LNG producers such as Indonesia, Malaysia, Oman, and Qatar, none of which had greenhouse gas abatement programs.
Representatives of the Australian LNG industry said LNG used in electricity generation produces 30-40% less greenhouse emissions than electricity generated from coal or oil.
The Australian Petroleum Production & Exploration Association had warned $25 billion (Aus.) of petroleum projects were in jeopardy because of federal initiatives on greenhouse gas and taxation issues.
It also wanted the government to specify details on depreciation rates for pending megaprojects.
As part of Australia's goods and services tax package the government scrapped accelerated depreciation schedules for major capital projects like offshore petroleum developments. Instead, it had pledged to provide assistance case by case.
Wood Mackenzie Consultants Ltd., Edinburgh, predicted that during 2000-10, ExxonMobil Corp. would become Australia's major onshore gas producer. The assessment covered only projected Australian gas production and not LNG production.
It said ExxonMobil's rise was due "to a steady increase in production from the Bass Strait in response to growing gas demand in Victoria and access to the New South Wales gas market through the Eastern Gas Pipeline, which was under construction."
Wood Mackenzie said ExxonMobil gas output would surpass that of Santos Ltd., the 2000 leader, by 2003.
BHP Petroleum Pty. Ltd., ExxonMobil's partner in the Bass Strait, was predicted to pass Santos to become the second most prolific gas producer in 2006.
It said Santos faced declining production in Southwest Queensland and the Cooper/Eromanga basin and in East Spar field off Western Australia.
Western offshore
Woodside Energy Ltd. in 2000 was preparing to produce its Legendre oil fields off Western Australia.
The Ocean Legend, a mobile production unit converted from a jack up rig, was to be placed on block WA-1-P, containing Legendre North and Legendre South fields.
Three horizontal production wells were planned in Legendre North and one in Legendre South.
Production from the $110 million (Aus.) project was due to begin before mid-2001. Peak production was expected to be 50,000 b/d. Produced gas would be used to power production facilities; the rest would be reinjected.
Woodside Energy estimated the fields contained 44 million bbl of reserves.
Crude would be moved through a 10-in. pipeline to a floating storage and offloading vessel. From there, the oil would be transferred to tankers.
Participants in WA-1-P were operator Woodside with 45.94%, Apache Energy Ltd. 31.5%, and Santos Ltd. 22.56%.
Texaco Inc. and partners had two gas discoveries in the Northern Carnarvon basin off Western Australia in early 2001.
The Iago-1, on exploration permit WA-25-P, and the Io-1 on permit WA-267-P followed the discoveries Geryon (1999), Orthrus (1999), Urania (2000), Maenad (2000), and Jansz (2000) made by Texaco and partners in the area adjacent to giant Gorgon gas field.
The Iago-1 was drilled to 11,100 ft TD in 387 ft of water. Logs and formation tests confirmed hydrocarbons in the Triassic Mungaroo. The Io-1 was drilled to 9,941 ft TD in 4,436 ft of water.
Texaco Australia Pty. Ltd. held 28.6% in WA-25-P and 25% in WA-267-P.
Partners were Chevron Australia Pty. Ltd. (the operator), Mobil Australia Resources Co. Pty. Ltd., and Shell Development (Australia) Pty. Ltd. BP Exploration (Alpha) Ltd. participated in WA-267-P only.
North West Shelf
Partners in the North West Shelf LNG venture were planning an expansion.
Woodside was operator. The other equal participants in the venture were BHP Petroleum, BP, Chevron, Shell, and Japan Australia LNG Pty. Ltd.
Woodside and partners were considering a $2.4 billion expansion involving a fourth LNG train at the onshore gas plant on the Burrup Peninsula.
Plans included a 4.2 million tonne/ year processing facility and a 42-in. trunkline linking the plant and gas fields 130 km offshore.
Agreeing to take LNG from the expansion were Osaka Gas Co. Ltd., 1 million tonnes/year for 30 years, and Tokyo Gas Co. Ltd. and Toho Gas Co. Ltd. 1 million tonnes/year beginning in mid-2004.
Most of the North West Shelf partners, except BHP, were backing Austeel Pty. Ltd.'s planned steel plant project in the Pilbara region of Western Australia. They agreed to invest $13.5 million (Aus.) in the plant, due to start in 2003. It would use 315 terajoules/day of gas for 20 years from the North West Shelf project.
The Corus Group (a merger of British Steel and Hoogovens) was to operate the plant, which would produce 4 million tonnes/year of steel.
The North West Shelf partners were developing Echo-Yodel gas-condensate field on the shelf.
Echo-Yodel is in 140 m of water 23 km southwest of Woodside's Goodwyn A gas production platform. The fields were being developed with subsea facilities. Gas and condensate would go to Goodwyn A for processing.
Work included a 23-km, 12-in. export pipeline, a subsea electrohydraulic umbilical, and a new riser caisson on the Goodwyn A platform incorporating a 12-in. production riser.
Echo-Yodel was expected to produce 37 million bbl of condensate and 4 tcf of gas over its 4-5-year life span. Slated to begin in 2002, Echo-Yodel production would offset the decline at the larger Goodwyn field.
Shale plant
In early 2001, a group led by Suncor Energy Inc. restarted oil shale processing at its Stuart plant near Gladstone in Queensland after a planned 3-month turnaround.
More than $6 million (Aus.) worth of equipment was installed at the plant as part of a program of emission and noise abatement. The work also included preventive maintenance.
Shale was reintroduced into the Alberta Taciuk Processor (ATP) in late November. Shale target rates of 150-160 tonnes/ hr were achieved. The feed rate represented 60-65% of plant capacity.
Suncor said odor sampling and noise abatement measurement showed improvement over commissioning runs earlier in the year.
The Australian partners in the project, Southern Pacific Petroleum NL and Central Pacific Petroleum NL, also reported low levels of dioxins in the plant's air emissions and spent shale.
Operations were due to gradually increase in 2001. Partners were planning a second stage with a feed rate of 25,000 tonnes/day of shale and production of 14,000 b/d of oil.
If successful, the Stuart project could lead to an 85,000-b/d operation by 2007.
The Stuart oil shale deposits, containing an estimated 29 billion bbl, were discovered in the 1970s and early 1980s along the Queensland coast. They hold some of the world's highest-quality shale in terms of oil yield.
Shale in the 400-m thick Rundle formation had only 15-25 m overburden, enabling open-pit mining. The shales have a 15-25% kerogen and 20-25% moisture content.
Gas projects
Ivanhoe Energy Inc., Bakersfield, California, spent $19 million for a 13% equity stake in Syntroleum Corp.'s Sweetwater 10,000 b/d gas-to-liquids project under development in Western Australia.
Ivanhoe also would provide $2 million for front-end engineering and other project development costs. Ivanhoe planned to use Syntroleum technology to produce large, stranded gas deposits.
The Sweetwater project would use Syntroleum's process to convert gas into ultraclean specialty products such as lubricants, industrial fluids, paraffins, and synthetic fuels.
The plant is in Western Australia's Burrup Peninsula. In February, Syntroleum signed a gas supply contract with North West Shelf Venture partners to supply 130 petajoules/year of gas as feedstock.
The State of Western Australia loaned Syntroleum $40 million (Aus.) for research and development and purchased a Syntroleum GTL fuel license for $30 million (Aus.).
Other license holders in Sweetwater included BP, Enron Corp., Kerr-McGee Corp., Marathon Oil Co., Texaco Inc., Repsol-YPF, and the Commonwealth of Australia.
Meanwhile, Shell Development Australia and Woodside Energy, partners in the Northern Australia Gas Venture, signed a letter of intent with Methanex Corp., Vancouver, BC, to supply 110 petajoules/year of gas for a proposed large-scale syngas plant near Darwin.
NAGV, which was formed to deliver offshore gas to Australia's Northern Territory, held interests in both discovered and potential gas fields in the Timor Sea off the northern coast.
Start-up of the syngas plant could come in 2005. A decision on the project was expected in 2002, pending NAGV verifying its gas reserves, receiving regulatory approval, and obtaining further customer commitments.
Timor Sea treaty
Australian government officials and representatives from the United Nations Transitional Authority in East Timor (UNTAET) began negotiations on the division of revenues from oil and gas production in the Timor Gap.
The arrangements would replace the Timor Gap Treaty signed by Australia and Indonesia in December 1989.
East Timorese leaders and UNTAET officials wanted a greater share of revenues, which were split 50:50 with Australia.
The fields were closer to East Timor than Australia. However, the Australian government had argued that the median line should be drawn along the edge of the continental shelf rather than midway between the coastlines of the countries. That would put the fields on the Australian side of the median because the deep Timor Trench is just off the south coast of East Timor.
The Timor Gap had been administered as a three-zone region, with the central zone (containing most of the discoveries in the area) being run by Joint Authority of Australia and UNTAET.
In 1999 production revenues from the Elang/Kakatua oil fields were $6 million (Aus.), but the figure was expected to grow as other fields came on stream.
The existing treaty covers the $2.6 billion (Aus.) Bayu-Undan liquids project due on stream in 2004 at 100,000 b/d of condensate and LPG. But there was no clear fiscal regime for valuing the gap's large gas deposits.
Phillips Petroleum Co. Australia, operator of the Bayu-Undan development, said a new treaty should be drafted to minimize development delays.
Potential projects include the Bayu-Undan Stage 2 gas development and the Woodside-Shell Australia Sunrise-Troubadour-Sunset project.
Timor projects
The Joint Authority approved Phillips' plan for the Bayu-Undan gas recycle project in 2000.
The $1.4 billion project would involve gas and liquids production from Bayu-Undan field, plus processing and storage of condensate, propane, and butane, as well as reinjection of dry gas into the reservoir. First liquids production from the project was expected in late 2003, and full commercial production in early 2004.
Bayu-Undan is a gas-condensate field that straddles PSCS 91-12 and PSC 91-13 in Area A of the Timor Gap Zone. The field, in 80 m of water 500 km northwest of Darwin, has estimated reserves of 400 million bbl of liquids and 3.4 tcf of gas.
Phillips had 50.3% of the project, Santos Pty. Ltd. 11.8%, Inpex Ltd. of Japan 11.7%, Kerr-McGee Corp. 11.2%; Petroz NL of Australia 8.3%, and British-Borneo Oil & Gas PLC 6.7%.
Meanwhile, AEC International (Australia) Pty. Ltd., a subsidiary of Alberta Energy Co. Ltd., Calgary, had an oil discovery in the Timor Sea. It was operator of the Puffin-5 well on AC/P22 Block with a 60% working interest. Partners were units of WestOil NL with 20% and Norwest Energy NL Ltd. with 20%.
Flow rate data was not obtained because of unexpected sand production.
Puffin-5 is 9 km from the Puffin-2 oil discovery that ARCO Corp. drilled in 1974. Puffin-2 flowed 4,608 b/d of oil from a separate Puffin Group sand.
Funding the project were field owners Woodside, Shell Australia Ltd., and Methanex Corp., and the Northern Territory government. Phillips Petroleum Co. and Osaka Gas Co. Ltd. were also partners.
Phillips and Shell were planning the first phase of the $4.7 billion (Aus.)
Sunrise-Troubadour-Sunset development project. It involved development of the Timor Sea fields and the building of a methanol and syngas plant near Darwin to use the gas.
The development would be Australia's fourth major gas production hub in the Timor Sea. The three fields hold an estimated 9.16 tcf of gas.
Onshore
Empire Oil & Gas NL confirmed the Rough Range discovery, made in the 1950s, with its Rough Range 1B.
West Australian Petroleum Pty. Ltd. discovered Rough Range in 1953. The field was not produced. The discovery well flowed 1,600 b/d from an 8 m oil zone. Ten appraisal wells were dry or found only traces of oil.
Drilled on the Exmouth Peninsula, Rough Range 1B flowed at rates as high as 1,608 b/d, said Empire.
A second well, Central Rough Range 1, was planned. A separate structure, Rough Range South, would be drilled later in the program.
Santos Group and its partners had a new-pool oil discovery on License 8 in the South Australian portion of the Cooper-Eromanga basins. The discovery was the group's third on the Moomba structure.
The partners drilled the Moomba 104 wildcat to 2,161 m TD, where it cut a 9-m oil column in Jurassic Hutton sand.
The well was 6 km south of the Moomba gas processing plant. Santos said the zone was capable of flowing 2,000-3,000 b/d of oil, based on comparable producing zones in the Cooper basin. The partners planned further drilling based on a 3D seismic survey shot in 1997.
Interest holders were Santos with 59.75%, Delhi Petroleum Pty. Ltd. 20.21%, Boral Energy Resources Ltd. 13.19%, Novus Australia Resources NL 4.75%, and OMV Group 2.1%.
Pipelines
The government of Queensland issued a policy to promote the proposed 1,988-mile, New Guinea-Queensland gas pipeline.
The Queensland Energy Policy, created to reduce greenhouse gas emissions, supported increased use of gas in Queensland while penalizing coal use, according to a Wood Mackenzie report.
The consultant said although the governments of Papua New Guinea, Australia, and Queensland had signed a memorandum supporting construction of the pipeline and ancillary facilities, financing was not yet in place.
Capital investment for the project was expected to reach $8.1 billion (Aus.). The pipeline and associated projects would hire 5,100 construction workers and a continuing workforce of 2,500.
Developer Chevron Services Australia Pty. Ltd., secured gas sales agreements for 66.5 bcf/year, sufficient to support the project.
The $3.5 billion pipeline system, $2.5 billion of which would finance delivery facilities in Queensland, was designed to deliver up to 600 MMcfd. Supplies would come from Papua New Guinea's southern highlands fields, which contain reserves of 8.99 tcf.
The 18, 22, and 30-in. pipeline system would include a wet gas line from the fields to an offshore processing plant in the Gulf of Papua, where LPG would be separated for domestic and export use.
From the plant, dry gas would be moved across the Torres Strait to Cape York and to Comalco Ltd.'s proposed $1.4 billion gas-powered alumina plant and other markets in Gladstone.
A short lateral to Townsville, on the coast north of Gladstone, would supply Stanwell Corp.'s proposed gas-fired power station, and a 286-mile extension to Brisbane was under discussion.
Refining policy
A report in 2000 by accounting firm Ernst & Young said Australia's largest four refiner-marketers lost a combined $61 million (Aus.) in 1999. They were Shell Australia Ltd., Caltex Australia Pty. Ltd., BP Australia Ltd. and Mobil Oil Australia Ltd.
The survey did not report individual figures. However, the companies reported profits on oil retailing and marketing operations of $282 million on an investment base of more than $10.68 billion in refining and marketing assets. That equaled an industry profit of only 0.5¢/l. of refined product. Ernst & Young said the companies averaged a return on assets of just 2.6%.
Australian refiners faced capital investment needs of $1.3 billion. Seven of the country's eight main refineries needed major upgrades to meet the Australian government's directive to produce low sulfur and low particulate fuels.
Shell, which faced a $280 million bill to upgrade its 72-year-old Clyde refinery in Sydney, said it would close the plant by 2006. The average cost to other refineries was $185 million.
Australia was to phase out leaded gasoline by Jan. 1, 2002. All gasoline and diesel made in Australia must meet a 50 ppm sulfur content standard by 2006 vs. the 500 ppm in 2000.
The government acknowledged the refiners' problems in its Downstream Petroleum Products Action Agenda. It pledged to support restructuring in the refining industry, provided the companies delivered clear public benefits.
The government pledged to support industry proposals for downstream mergers that were submitted to the Australian Competition and Consumer Commission. It also agreed to review its plan to require ultralow sulfur diesel.
Avgas problem
About 5,000 piston-engine aircraft were grounded in early 2000 after using aviation gasoline made at Mobil's Altona refinery Nov. 21-Dec. 23, 1999.
The fuel contained the anticorrosive agent ethylene diamine, and contamination caused the planes to develop fuel-system deposits.
Mobil offered $15 million (Aus.) to compensate the affected parties, but lawyers and aircraft operators estimated the losses at $50 million/month.
The Civil Aviation Safety Authority ordered the affected aircraft to flush their engines before flying. It later
said a second problem had been discovered: When uncontaminated avgas was used in planes that had been purged of the Mobil product, the deposits returned.
CASA said the contaminant was noticeable as a black viscous deposit on copper and copper alloys.
Avgas is made by selecting the high-octane output from isomerization, alkylation, and catalytic reforming units. The components are blended with additives to suppress gum formation and engine deposits. The vapor pressure is then adjusted by adding butane.
