The Bass Strait region off Australia's southern coast is expected to remain the mainstay of the country's oil production in the near term.
Government and industry see Australia's western offshore areas as the key to maintaining the country's level of oil self-sufficiency at an acceptable level beyond 2000 (OGJ, Aug. 17, p. 29). But Bass Strait oil flow, in decline since 1985, at about 300,000 b/d still provides more than half of Australia's current production.
Principal Bass Strait producers Esso Australia Ltd. and BHP Petroleum Pty. Ltd. contend the Bass Strait will be a significant contributor to Australian oil production well into the next century.
Bass Strait operators have a healthy program of exploration and development on tap in the near term. Chief focus will be in the Gippsland basin, off Victoria's southeast coast, which currently provides most Bass Strait oil and gas production.
However, there has been renewed interest lately in the Otway basin off western Victoria and in the Bass basin off northern Tasmania.
GIPPSLAND OVERVIEW
The Gippsland basin supplies almost all of Victoria's natural gas and exports large volumes of liquefied petroleum gas, mainly to Japan.
There are 18 offshore production facilities in the Gippsland basin: 14 steel platforms, two monotowers, and two subsea completions.
Bass Strait oil production has declined from its peak of about 500,000 b/d in 1984.
Esso-BHP's giant Kingfish field, Australia's biggest, produced its billionth barrel of oil last month. Kingfish, discovered in 1967 and brought on stream in 1969, produces from three platforms.
Although the field is in decline, a recent infill drilling program on the West Kingfish platform has boosted field flow to 60,000 b/d.
The Esso-BHP joint venture that accounts for all Gippsland production has this year embarked on a $67 million (Australian) exploration program in the region. In addition, the combine is expected soon to announce contracts for two more production platforms.
The venture's exploration and development plans each involve a first for the Bass Strait.
GIPPSLAND EXPLORATION
On the exploration front, Esso-BHP spudded in late July its Ra Whaleshark wildcat in the southeast part of the basin in 720 m of water.
This is by far the deepest water tackled by the combine in the region. The Whaleshark prospect lies 80 km off the Victoria coast on the continental slope.
Although relatively close to existing infrastructure--the nearest platform is 30 km away in Flounder field--any discovery will have to be a substantial oil find to be economic in such deep water.
Few details have been released about the prospect, but the potential is that of a world class structure, judging from results of seismic data acquired during the past 12 months.
Drilling is expected to take 2 months using the Atwood Falcon semisubmersible, which will employ a combination of dynamic positioning and conventional anchor pattern techniques to move onto and then stay on location.
Esso-BHP will follow Whaleshark with an appraisal well, 2 Blackback, in 400 m of water. The Blackback structure, which also lies on the continental slope, caused some excitement in 1989 when Esso-BHP tested 1,500 b/d of oil from a poor reservoir sand in the 1 Blackback wildcat.
The appraisal this year will search for better sands in the prospect, and hopes are high for success, Particular encouragement is drawn from the fact that the nearby Hapuku and Terahiki wildcats found good sands containing oil shows.
The two new wells are part of a $50 million exploratory drilling program (OGJ, Mar. 9, p. 30) that coincides with a $17 million, 26,000 line km 2-D and 3-D seismic program, the largest undertaken in the Gippsland basin.
The Pacific Titan seismic vessel is to stay in the region until early 1993, further delineating a number of prospects that were first identified in a 1991 survey.
Continuing interpretation of new prospects is one of the reasons for Esso-BHP's confidence in longevity of the Gippsland basin. The combine also points out that a viable oil discovery involving prospects such as Whaleshark and Blackback has the potential to rejuvenate Australia's oil outlook.
Although a number of other groups hold exploration permits surrounding the Esso-BHP production areas in the Gippsland basin, there is little activity planned soon.
OIL DEVELOPMENT
Two proposed oil field development projects--Bream B and West Tuna, formerly Tuna B--in the Gippsland basin are on the verge of a green light.
Combined development cost is estimated at $800 million. Project teams have been working on both platform designs for 12 months and, although a final decision hasn't been made, it seems likely that development will take place with the first concrete structures off Australia.
The concrete platforms would be built at Port Kembla on the New South Wales coast. These gravity structures hold appeal in Bass Strait, where there have always been difficulties with the soft, calcareous nature of the seabed, notorious for "fluidizing" around the piles of a steel platform when subjected to stress.
The West Tuna platform--with 48 wells, the largest by far in Bass Strait--will be designed to develop oil reserves of as much as 86 million bbl.
Bream B will tap about 18 million bbl of oil in an extension of Bream field that can't be reached by wells from Bream A platform. Esso, operator of the project, says West Tuna has a 30,000 b/d production potential and Bream B 12,000 b/d.
Other possible Gippsland basin developments in the next few years include Yellowtail-South Mackerel oil, estimated in its early appraisal to contain as much as 14 million bbl. A development project could consist of a five slot gravity base monotower tied back to the Mackerel platform. A preliminary estimate of development costs is $100 million.
There is also the Turrum oil discovery underlying Marlin field. Early estimates place reserves at 10-20 million bbl. The reservoir also has associated gas, and it is likely any development would focus on oil and gas and link with Marlin facilities. Initial cost estimate for Turrum development is $250 million.
GAS DEVELOPMENT
On the gas front in the Gippsland basin, the most likely future development is the 1986 Kipper discovery.
At the moment Kipper development depends almost entirely on gas sales at the right price. At this stage that is lacking, and the situation appears unlikely to change before 2000.
Esso and BHP are particularly concerned that the Australian government's resource rent tax now applies to all production from Bass Strait, including for the first time natural gas production. The companies argue this is inappropriate because it will increase the price of gas and make it even more difficult to penetrate new markets.
Although there is oil and condensate associated with Kipper, perhaps 30 million bbl in place, Kipper is mainly a gas field with reserves estimated at 750 bcf.
In a development related to Gippsland basin gas production, BHP has won approval to build a $68 million pilot methanol plant at Werribee just west of Melbourne to test the viability of a domestic methanol industry.
Using British technology, the plant is to produce as much as 60,000 metric tons/year of methanol from Bass Strait gas. The gas will be taken directly into the plant from the western Victoria gas grid.
BASS BASIN ACTIVITY
After a number of years in the doldrums, there will be a short burst of wildcat drilling in the Bass basin in Tasmanian waters this year.
Sagasco Resources Ltd. plans two wells in the northwest part of the basin. The first is planned near the noncommercial Pelican gas/condensate strike made in the 1970s and the second near the 1985 Yolla oil and gas/condensate discovery.
The possibility of development at Yolla caused a flurry of expectation in Tasmanian political and industrial circles earlier this year until negotiations over gas prices broke down. The Sagasco group is still keen to see development go ahead.
The field, 135 km north of Burnie on the northern Tasmanian coast, is not fully appraised. Early estimates of reserves are 300-400 bcf of gas, 7 million bbl of natural gas liquids, 30 million bbl of condensate, and 3 million bbl of crude oil.
The concept in mind calls for an offshore gas platform housing separation facilities, a two phase pipeline to shore, and onshore facilities to remove water, carbon dioxide, and gas liquids.
Cost of such a development would be about $500 million. However, it is likely at least one more well will be needed to delineate the structure.
The economics may well be enhanced if there is success in either of the two wildcats planned in the region for this year.
OTWAY BASIN REVIVAL
The Otway basin off western Victoria and eastern South Australia also will see a brief exploration revival this year.
A venture of Shell Australia Ltd. and Woodside Petroleum Ltd. plans to drill the I Wild Dog wildcat relatively close to the Victorian coast in the Torquay subbasin. Shell, as operator, will use the rig Sagasco's hired for its two Bass basin wells for the one well program, as well as the same supply base in Tasmania.
Perhaps more visible because it has been targeted by Greenpeace and other environmental groups is the four well program BHP plans on neighboring permits to the west. Now in the final stage of processing seismic surveys run last year--which were disrupted by protestors, leading to litigation that later was dropped--BHP's drilling program will begin near yearend and continue into 1993. Little further is known about the prospects at this stage.
Shell and BHP drilled in the offshore Otway basin during the 1960s without success.
It is one of the few regions in Australia where there is evidence of oil being washed ashore, particularly after storms and earthquakes. The presumed source is under the seabed off the Otway coast.
This evidence of offshore seeps prompted Australia's first oil exploration effort, along onshore coastal South Australia, in the 1860s.
Oil shows and commercial gas--Katnook in South Australia and North Parratte in Victoria--have been found onshore, but there never have been more than a few shows in offshore wells. It is now thought that a number of those wells were off structure and new seismic data gives a much more accurate picture.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
