Australia's hopes seem bright for beginning the next century with a level of oil self-sufficiency within 10 percentage points of its current 85% level.
It's a prospect most forecasters had dismissed in the mid-1980s. At that time, oil production in Bass Strait, the country's mainstay for 25 years, had begun to decline. Many observers believed the country's level of self-sufficiency would fall with it, perhaps to as low as 40% by 2000.
But impending production start-ups from a flurry of discoveries off Australia's northwest coast have turned that outlook around. According to the latest predictions from the Australian government's Bureau of Mineral Resources in Canberra, it now seems likely Australia will end the 1990s with a 75% level of self-sufficiency. The Australian Petroleum Exploration Association (APEA) predicts Australia's oil self-sufficiency will fall to about 71% by the mid-1990s (OGJ, June 8, p. 29).
In fact, fields outside Bass Strait already contribute half of Australia's oil production. More will go on stream in the middle of the decade to replace current production.
Even so, the country's exploration and development companies see no room for complacency. Confidence in the future is still fragile, as can be seen by APEA activity forecasts for 1992 (see chart, p. 30).
All monetary values in this story are in Australian dollars.
EXPLORATION FACTORS
Future exploration and development in Australia hinges on three factors.
First, almost the entire focus of future exploration is offshore. There is a continuing program in Bass Strait, but by far the greatest concentration of effort will be on the Northwest Shelf, where the recent string of finds have been made.
Apart from the Cooper/Eromanga basins of South Australia and Queensland, there is little attention being paid to the country's vast and still largely untried onshore sector.
In terms of offshore exploration, Western Australia is by far the most active region. About half the country's likely total of 30-50 offshore wildcats this year will be drilled off the state's northwest coast. Most of them will be in the Carnarvon basin on prospects made more encouraging by the recent finds in the region and in the Browse basin farther north. One or two will probe the Perth basin in the south, which has not been tested since the 1970s, and the Bonaparte basin in the far north.
The second key exploration factor is that although the level of seismic activity is up sharply from 1991, most of the surveys being run are 3-D, usually associated with appraisal of existing discoveries and/or looking at the possibility of delineating viable extensions.
Very little effort is being devoted to wide ranging regional surveys, which means that few of the wells to follow will be rank wildcats attempting to open new provinces onshore or offshore.
The third prime exploration element is that a large slice of the exploration budgets for Australian companies will be spent on programs outside the country. This way, companies effectively are hedging their bets on Australia's prospectivity against its fiscal regime and more recent worries about the growing number of impediments to access to onshore and offshore permits.
The dilemma for the future is that while existing discoveries probably will carry the country through the 1990s at current oil self-sufficiency, there is an urgent need to make a number of significant discoveries during the next 4-5 years to ensure that today's petroleum supply/demand balance is maintained beyond 2000.
Although the skill of explorers is a critical factor in any discovery, success also depends on the number of wells drilled. In good times, explorers flock to the region surrounding a new discovery.
However, in times of recession in the industry and the economy as a whole-as is the case now-the level of exploration activity in Australia remains highly sensitive to changes in government policies-particularly on taxes and the environment.
APEA'S VIEW
As former APEA Chairman Bruce McKay pointed out during the association's annual conference last May, it appears that segments of the public and government perceive oil exploration as a dangerous industry that is highly profitable, environmentally irresponsible, and controlled by big players.
That, he said, is exactly what the Australian industry is not. Such a perception is a worrisome aspect when looking at the future for oil and gas exploration in the country.
He also noted that although the Australian exploration and production industry earned an average profit of just a little more than $1.1 billion/year the last 4 years, companies paid more than $10.8 billion in taxes during the same period. In addition, when profits are compared with industry investment of $20 billion, the resulting average after tax return on capital employed for those 4 years of just 8.2% is far from satisfactory, McKay said.
On environmental matters, APEA is concerned about the increasing number of regulations and impediments to access to land for exploration and the lack of a rational, analytical approach to environmental management issues.
In an effort to redress that, the association has commissioned an independent review of scientific research on the consequences of exploration and production on the marine environment. The aim is to build a greater awareness among scientists, government, environmental organizations, and the public of the industry's good record. APEA also hopes the review will establish broad acceptance of the industry as a legitimate user of marine resources and suggest further areas of joint research.
McKay pointed out that the country should be trying to achieve sustainable development-not sustainable stagnation, as some would promote.
Still there remains a number of new and prospective project developments plus hot exploration spots around the country that represent the industry's future prospects in Australia.
There are plans for additional oil platforms in Bass Strait, a major onshore gas development in Southwest Queensland, and the expectation of a new exploration province in the Timor Gap Zone of Cooperation between Australia and Indonesia.
But it is the recent oil discoveries off Western Australia that provide the engine for growth in exploration and development programs.
WESTERN AUSTRALIA PRODUCTION
Oil, condensate, and gas production from Western Australia is at a record level, maintained in 1991 with start-up of Beharra Springs and Tubridgi gas/condensate and Cowle and Yammaderry oil fields.
Those four bring the total number of producing fields in the state to 23-10 offshore and 13 onshore.
Oil production in Western Australia rose 2% from the 1990 total of 31.8 million bbl to 32.6 million bbl.
Increased production from Harriet, South Pepper, and Talisman fields, along with first oil from Cowle and Yammaderry, offset the natural decline from other fields. These include Saladin which, despite a decrease in production from about 45,500 b/d to 39,000 b/d during the year, remained the state's largest oil producer. Saladin contributed 43% of Western Australia's oil production in 1991.
The state's oldest field, the 1964 Barrow Island discovery, is still flowing 14,000 b/d and will produce its 250 millionth bbl of oil before yearend.
However, abandonment looms for Talisman. The Marathon Petroleum Australia group has begun plans to abandon the two well field. It originally was to be shut in during June, but that was delayed until September.
Storm damage forced the Acqua Blu production/storage vessel to Singapore for repairs, and it is unlikely to return. Marathon is seeking another rig to plug the wells.
Talisman, discovered in 1984 and on stream in 1989, has produced about 7.7 million bbl. Interests are held by Marathon 52.63%, Santos Ltd. 27.37%, and Ampol Exploration Ltd. and Lasmo plc 10% each.
Condensate production in Western Australia increased 9% from slightly more than 11 million bbl in 1990 to a little more than 12 million bbl in 1991.
The state's gas sales in 1991 rose 8% from the previous year. Contributions to the gain came from new onshore fields Beharra Springs in the Perth basin and Tubridgi in the Carnarvon basin, but most came from the Northwest Shelf to fulfill contracts for sales of liquefied natural gas to Japan.
Total sales gas production for 1991 was 473 bcf - 184 bcf of that for LNG production -compared with 437 bcf in 1990.
A number of major new developments are under way in Western Australia, representing the main concentration of oil and gas projects in Australia at the moment. Heading the list is the Goodwyn project, involving the second gas/condensate production platform for the Northwest Shelf gas development and the third LNG train at the Burrup Peninsula liquefaction plant.
NORTHWEST SHELF UPDATE
The Northwest Shelf project produced 4.1 million metric tons of LNG in 1991 in its progress toward a goal of 7 million tons/year in the mid-1990s.
Gas sales to Western Australia's market from the Northwest Shelf project totaled 354.3 MMcfd, up from 347.8 MMcfd in 1990 due to increases in volumes for power generation.
The $1 billion Goodwyn development, third phase of the Northwest Shelf project following the domestic gas and initial LNG phases, is nearly complete.
The project's third LNG train is expected to be on stream in time to meet sale contract volumes to Japan in 1993. Commissioning of the third train is expected in October, while the arrival of the project's sixth LNG carrier, Northwest Sea Eagle, is scheduled for November. A seventh carrier, Northwest Sandpiper, is to join the project fleet in February 1993, and an eighth has been ordered.
The Goodwyn platform jacket is scheduled to leave its construction yard at Batam Island, Indonesia, early in October and be piled into position prior to the cyclone season. Topside module installation and hookup then is to be complete early in 1993 after the danger from cyclones has passed.
The Northwest Shelf group, led by Woodside Petroleum Pty. Ltd., expect to supply 107 LNG cargoes in 1993.
What's more, with existing strong demand and prospects for further growth, participants have begun preliminary evaluation for development of LNG trains 4 and 5, perhaps to go on stream by the turn of the century to boost LNG capacity to 12.5 million tons/year.
Such a program will require proving about another 4 tcf of gas reserves. Part of the Woodside group's exploration program the next few years will focus on finding and confirming gas fields.
Shell Australia outlined such a program last month, one that would call for a further outlay of $6-9 billion (OGJ, July 27, Newsletter).
Nearby finds, including Angel, Echo, and Yodel, await further appraisal and may become part of this new development program toward the end of the 1990s.
In the meantime, the Goodwyn platform, scheduled for start-up next year, will at first focus on production of the field's condensate reserves. Gas will be used a little later in the decade to bolster production from North Rankin field and produce 7 million tons/year of LNG by the mid-1990s.
LNG deliveries are expected to rise to 5.14 million tons in 1993, 5.92 million tons in 1994, 6.73 million tons in 1995, and 6.9 million tons in 1996.
The project shipped its 10 millionth ton and 174th cargo of LNG to Japan in mid-June. Shipments began less than 3 years ago.
HADSON PROJECT
Another important gas project off Western Australia is Hadson Energy's $125 million development program in Campbell, Sinbad, and Rosette fields. Gas production also will come from nearby Harriet and Tanami oil fields.
Deliveries to the State Energy Commission of Western Australia (Secwa) began at 26 MMcfd this month. Initial production is flowing from Harriet and Rosette fields, with miniplatforms producing from one well in Campbell and two in Sinbad to start up within the next 2 months.
Secwa has committed to buy 130 bcf during 10 years. The Hadson group has options to supply another 60.5 bcf during an additional 5 years.
The untapped Bambra field could be used as backup reserves and/or justification for pursuing other markets.
Development work included installation of two single leg platforms and 30 km of in-field gas pipelines to nearby Varanus Island (OGJ, Aug. 26, 1991, p. 24).
There also is a 100 km gas pipeline-70 km offshore and 30 km onshore-from the island to the mainland connecting with Secwa's gas trunk line running from the Northwest Shelf project to the southwest coast of the state.
GRIFFIN FIELD
Western Australia's newest oil development is the BHP Petroleum Pty. group's Griffin field complex southwest of Barrow Island.
Announcing its $600 million plan in May (OGJ, May 18, p. 32), BHP said it will combine Griffin development with nearby Chinook and Scindian discoveries using subsea completions and flow lines connecting through a floating riser system to a 1 million bbl capacity floating production and storage unit (FPSU).
The project is expected to come on stream in March 1994. Total recoverable reserves from the three fields are estimated at 130 million bbl.
A feature of the development is that no gas will be flared. Some gas will be used to power offshore facilities and some will be reinjected for pressure maintenance.
However, most of the gas will move via pipeline 68 km to the mainland for sale in Western Australia.
Partnership interests in the three fields, all on Permit WA-210-P, are BHP 45%, Mobil Exploration & Producing Australia Pty. Ltd. 35%, and Inpex Alpha Ltd. of Japan 20%.
ROLLER, SKATE
A smaller oil development project in the same region is West Australian Petroleum Pty. Ltd.'s (Wapet) Roller and Skate fields, expected to produce at combined peak rates of as much as 68,000 b/d when they go on stream in mid-1994.
The two fields lie just off the coastal town of Onslow and about 20 km south of Wapet's Saladin development. Recoverable reserves are pegged at about 32 million bbl, most of which lie in the Roller reservoir.
Wapet's plans include installation of three monopod platforms and as many as five wells in Roller plus a single monopod housing one or two wells on Skate.
Oil will move by pipeline to the Saladin complex for transfer to existing facilities on nearby Thevenard Island. Gas produced will be reinjected for pressure maintenance.
A $3 million detailed engineering and design study is under way. Total project cost is expected to be about $150 million.
WANAEA, COSSACK
Another big find under development consideration off Western Australia is the Woodside group's Wanaea oil and gas field.
Probably more than any of the recent successes, Wanaea has sparked the rejuvenation of oil hopes on the Northwest Shelf. Oil has been found in the region on a number of occasions since drilling began in the mid-1960s with the first well, 1 Legendre, recovering oil to surface. But most accumulations have been small and, with the exception of Talisman, uneconomic.
Wanaea is by far the largest oil discovery so far with reserves estimated at 165 million bbl. The field also has a high gas:oil-almost 1,000:1. In addition, the gas is very wet.
In fact, the natural gas and LPG components have made a development decision more difficult because the project will need to find a market for the gas or reinject it. If Wanaea gas is introduced to the Northwest Shelf gas project, added LPG handling facilities will probably be needed at the Burrup Peninsula treatment plant.
A further complication is the recent downgrading of estimated oil reserves in nearby Cossack field to 30 million bbl from 60 million bbl. The 3 Cossack appraisal well cut a 13 1/2 m oil column instead of the 35 m column predicted.
Cossack was to have been developed with a floating production unit and subsea wells, as in the Griffin project, going on stream in third quarter 1993 and producing at a peak 60,000-80,000 b/d. That development plan has been put on hold, and it now seems likely Cossack will be developed in conjunction with Wanaea.
The most probable program would involve a fixed platform in Wanaea with at least 12 wells along with two or three subsea wells in Cossack connected by flow lines to the Wanaea structure.
The FPSU purchased for Cossack prior to the downgrading of reserves could then be used for Wanaea and Cossack production alike, while gas is produced via pipeline into the main North Rankin-Burrup Peninsula trunk line. The FPSU has been laid up to await a final development plan.
Also some of the surrounding small oil strikes made in the 1960s and 1970s such as Egret and Lambert-uneconomic on their own -could be fed into the Wanaea network.
At this stage all the options, including the use of a steel or concrete platform, are being studied by the Woodside group. A decision is unlikely before early 1993, suggesting a possible on stream date of 1995-96. Depending on the type of development, total investment for Wanaea/Cossack could be $600-800 million.
Indications are that the combined development could yield 100,000 b/d, split 70,000 b/d for Wanaea and 30,000 b/d for Cossack.
The Woodside group had a setback in Wanaea plans last month when its 5 Wanaea appraisal on the northwest flank of the structure cut only a watered out reservoir section. It was drilled to 3,210 in.
Woodside operates both fields on behalf of partners BHP, BP Developments Australia, Chevron Asiatic, Shell Development (Australia), and Japan Australia (MIMI), each with a one-sixth interest.
GAS, GAS/CONDENSATE
Under consideration off Western Australia are big projects involving development of gas and gas/condensate fields.
Gorgon and West Tryal Rocks fields were discovered by Wapet in 1980 and 1972, respectively. Gorgon has estimated reserves of 5.4 tcf of gas and 21 million bbl of condensate, and West Tryal Rocks has a likely 3 tcf of gas and 19 million bbl of condensate.
Often described as a potential second Northwest Shelf project, the Wapet group is considering for Gorgon/West Tryal development a proposal similar to that established at North Rankin-Goodwyn.
Despite the uncertainty with timing, Wapet conducted a large 3-D seismic program over the Gorgon structure this year.
In addition, screening and feasibility studies are being carried out in an effort to define a viable gas project, Early work suggests a large, multiplatform development is possible. However, a commitment is unlikely before the end of the 1990s.
The Barrow Island gas project, also a Wapet initiative, hinges on negotiation of a gas sales contract, results of appraisal drilling, and the potential for use of current wells.
Wapet pegs gas reserves at Barrow, discovered in the 1970s, at 300-500 bcf.
The project, if it goes ahead, is likely to cost $30 million, It will entail drilling high pressure gas wells and installing a gas gathering system as well as a gas processing plant. Treated gas would move by pipeline to the nearby Harriet project on Varanus Island, then to the mainland via the Harriet gas trunk line.
A third-but much more speculative -possibility is development of the Scott Reef-Brecknock gas/condensate discoveries in the Browse basin farther northwest.
Scott Reef and Brecknock fields, found by the Woodside group, are giant reservoirs with prospective reserves estimated at 9 tcf and 12 tcf, respectively. However, they lie about 250 km off Western Australia's northwest coast and are unlikely to be considered for development before early in the next century.
RAMILLIES, LEATHERBACK
Much closer to realizing their potential are Ramillies and Leatherback, recent smaller oil discoveries on the Northwest Shelf.
Ramillies was found by BHP and Ampol Exploration Ltd. of the permit adjacent to Griffin in December 1990. Pending arrangements between the two groups involved-expedited by the fact that BHP is operator of both the field could be tied into the Griffin development. However, at this stage there is no definite move to do so.
Leatherback is an oil discovery drilled by Lasmo Oil (Australia) in July 1991 near the mouth of the Exmouth Gulf in 14 in of water. The oil column measured 7 in, and testing produced a flow of 41 oil at rates of as much as 2,400 b/d.
At this stage there are no moves toward development, but results of a 3-D seismic survey are expected before yearend. Potential would be enhanced by discoveries in other prospects still to be drilled in the vicinity.
WANDOO FIELD
Ampolex confirmed Wandoo field with its 2 Wandoo on Permit WA-202-P about 70 km off Dampier and near the Woodside group's gas/condensate pipeline. It flowed 2,000 b/d of 10.7 gravity oil with no water through a 14 mm choke.
The well was intended to test the reservoir's water coning characteristics. The production test was carried out over a 3 in interval to 628.2 m.
The well was drilled to 1,546 m before being plugged back to 1,103 m when wireline logs showed the lower zones were water filled. More tests were planned this summer at 612-614 m.
The 2 Wandoo was drilled 1.7 km northeast of the June 1991 discovery, and initial reports indicated a similar structural and stratigraphic relationship.
Preliminary estimate of Wandoo potential reserves is 30 million bbl. Ampolex has a 100% interest in the permit following its purchase of ARCO's interests earlier this year. Plans call for a second appraisal to test the east-west extent of the discovery.
The Wandoo discovery is 75 km from the Burrup Peninsula and only 7 km from the Northwest Shelf gas pipeline. The well tested 18.7 oil at rates of as much as 4,600 b/d.
Ampolex 3 Wandoo, completed 1.9 km northeast of 1 Wandoo on the eastern flank of the field last month, convinced Ampolex it has 200 million bbl of oil in place. The company has not estimated likely reserves, saying only that initial modeling suggests normal recovery rates, with individual well rates expected to be good.
The 3 Wandoo was designed to determine, without production testing, the gas/oil and oil/water contacts on the eastern flank of the field. It confirmed Ampolex's predrill mapping and indicated continuity of reservoir sands in the first two wells.
Ampolex plans to begin further engineering studies and is considering a long production test to determine the best program for full scale development. It plugged 3 Wandoo as an unsuitable production location after conducting additional formation tests at 626.4 in and 636 in that recovered 1 l. of oil and 9.2 l. of filtrate and 1.25 l. of oil and 23.25 l. of filtrate and formation water.
Further appraisal drilling is planned in January.
OUTLOOK
Australia has a number of other potential new projects scattered around the country.
Among them are:
- Hoped-for development of Petrel gas field in the Bonaparte Gulf.
- Supplying gas to the Mount Isa area in Northwest Queensland.
- Supplying gas from Central Australia to the alumina refinery at Gove in the northeast corner of Northern Territory.
However, those projects have been on hold for some time, and all still depend on negotiations on gas prices and environmental considerations. It will be a slow process.
Consequently, the focus of most Australian explorationists, for the immediate future at least, is on the potential for significant new oil discoveries with much shorter development lead times.
And that is leading them to the offshore regions of the country's northwest.
However, the question remains: Is this narrowly focused effort enough to provide the best chance of maintaining Australia's oil self-sufficiency in the long term?
Perhaps a big discovery in the current hot spots will do it, but many industry observers would be happier with a broad based approach that sees explorationists also taking chances in a number of rank wildcat regions.
Forecasters may be more confident about Australia's outlook for the 1990s than they were several years ago, but none is willing to hazard a guess about the country's prospects for the early part of the 21st century.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
