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Bass Basin, Tasmania 2002 And 2003 Release Areas New Data On Oil Migration And Accumulation

CSIRO and Geoscience Australia have conducted a fluid history investigation of palaeo oil migration and accumulation in the Bass Basin, Tasmania. This study is relevant to current petroleum exploration release areas T02-3 and T02-4 in the western Bass Basin, as well as three areas in the eastern Bass Basin that are proposed for gazettal in March 2003. Bids are scheduled to close on April 10th, 2003 (2002 Release Areas) and late March 2004 (2003 Release Areas).

Sixteen wells were investigated, including Aroo-1, Bass-3, Chat-1, Cormorant-1, Flinders-1, King-1, Konkon-1, Pelican-2 & -5, Pipipa-1, Seal-1, Squid-1, Tilana-1, Yolla-1 & -2 and Yurongi-1. The objectives of the study were to evaluate hydrocarbon charge history of the Eastern View Coal Measures (EVCM) using CSIRO Petroleum's GOI™ (Grains containing Oil Inclusions), QGF (Quantitative Grain Fluorescence) and QGF-E (Quantitative Grain Fluorescence- Extract) techniques. Several palaeo oil zones within deep intra-EVCM reservoirs of late Paleocene to early Eocene age have been identified, with evidence for an upper EVCM petroleum play sealed by the Demons Bluff Formation. These data provide new insights into the petroleum potential of the Bass Basin, and will be useful in evaluating hydrocarbon charge risk in the basin.

The GOI, QGF, and QGF-E data, together with logs and an integrated interpretation, will be offered as a non-exclusive report available in March, 2003.

A summary of these data, along with other aspects of Bass Basin petroleum source rocks and oils, will be presented by Geoscience Australia at the 2003 APPEA conference in Melbourne, 23-26 March and can be viewed at www.petroleum.csiro.au/research/om.html.

Enquiries relating to the report should be directed to CSIRO Petroleum: Dr. Peter Eadington (Peter.Eadington@csiro.au), and Dr. Richard Kempton (Richard.Kempton@csiro.au), telephone 08 6436 8500 (Perth). Geoscience Australia: Dr. Chris Boreham (Chris.Boreham@ga.gov.au), telephone 02 6249 9488 (Canberra).

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Double Island Ready For First Oil

The Harriet Joint Venture (HJV) Double Island oilfield development in TL/9, off the Western Australian coast, has been completed and is expected to produce about 4.5 MMbbl of oil (proved and probable), according to joint venture partner Tap Oil.

Tap Oil Managing Director, Paul Underwood, said the initial planned production rate was estimated at 4,000 bopd. "This new development is another addition to the successful "String of Pearls" oil fields south of the HJV production hub on Varanus Island", Underwood said.

There are now eight oil fields tied back through the Simpson area, including Tanami, Simpson, Gibson, South Plato, Victoria, Pedirka, Little Sandy and Double Island. "All these fields have been discovered and quickly brought on stream over the last two years, and are expected to make a significant impact on Tap's oil production and profits over the next few years."

The Double Island oil field, discovered in January 2002, is about 10 km southwest of the Varanus island production facilities and about 7 km west of the recently installed Victoria platform. The development consists of a single well head, unmanned, micro-platform tied back to the Victoria Area platform for ultimate processing at the Varanus Island processing plant.

The Harriet Joint Venture participants are: Apache Energy (operator 68.5%), Kufpec Australia (19.2771%) and Tap Oil (12.2229%).

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Woodside Increases Bonaparte Equity

Woodside Energy has increased its equity in the Bonaparte Gulf, including the Blacktip gas discovery (in permit WA-279-P), after it bought out Shell Development (Australia's) interests in three permits during February.

Woodside's Gas Business Unit Director, David Maxwell, said the acquisition was consistent with the company's strategy of increasing the value of its existing gas assets. "Consolidation of ownership in the Bonaparte Gulf increases our interest in Blacktip and in prospective acreage in the region", Maxwell said.

Woodside has increased its interest in WA-279-P from 35% to 70%, WA-313-P from 33.33% to 66.67% and NT/P57 60% to 70%. The other joint venture partner in the permits is Agip Australia which maintained its equity in the permits at 30%, 33.33% and 30%, respectively. Woodside will continue to operate the permits.

The Blacktip field was discovered in September 2001 and, according to Woodside, has an estimated scope for recovery of 1.1 Tcf of gas.

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New Industry Department For WA

The West Australian Government has created a Department of Industry and Resources to manage the resources and non-rural industry sectors, after it merged the Department of Mineral and Petroleum Resources and the Department of Industry and Technology.

Premier Geoff Gallop said the new department was created following a structural review which identified duplication and competition for resources within the public sector. He said the new department would improve service delivery to all "key State development stakeholders".

"It is essential for us to have a fully co-ordinated approach to exploiting new and exciting opportunities", Gallop said. "With minerals, petroleum, resources, industry development and trade working as one, we have a powerful tool to shape the development of the State."

The Department of Industry and Resources will form part of the State Development portfolio under Minister Clive Brown. Its Director General will be Jim Limerick. The department opened for business under its new name on February 3rd.

$2 BB Methanol Plant Deferred

Plans for the development of a $2 BB methanol plant by Canadian methanol producer Methanex, on Western Australia's Burrup Peninsula, have been put on hold because of higher than expected capital costs.

Methanex's Senior Vice President for Asia Pacific, Bruce Aitken, announced on March 13th that the proposed development had become "increasingly difficult to progress in its originally intended form." "For Methanex, the capital costs for a greenfield project of this size have become disproportionately high", he said. Aitken said northwest Australia remained an attractive location for the company to build the plant.

"We are evaluating several alternatives, including installing capacity in smaller increments that would be more manageable from a cost perspective. Our Asian customers are very important to us and we are committed to maintaining our position in Asia."

Methanex President and Chief Executive, Pierre Choquette, said Australia was still the preferred location of a new supply source for the Asia Pacific region.

Western Australian State Development Minister, Clive Brown, said the government had been working closely with Methanex over the past two years to bring the project to fruition. "It is the government's understanding that Western Australia remains the preferred location for this investment", he said in a statement.

"Methanex remains a highly valued and highly desirable investor for Western Australia and the government will continue to work hard to resolve all issues within its control", Brown said.

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West Oil Buys Into Crackling Prospect

West Oil has acquired a 22.5% interest in EP-341 in the Carnarvon Basin where the Crackling South prospect is scheduled to be drilled by the Ensco 53 jackup drilling rig in April, 2003.

EP-341 operator Tap Oil has interpreted Crackling South as having a potential 30 MMbbl of recoverable oil. The prospect is located in 12 m water depth and the prognosed depth to the Birdrong Sandstone, the main objective sands, is about 350 m.

West Oil Managing Director, Charles Morgan, said there were many other similar prospects in the permit area if Crackling South-1 was successful. Interest holders in EP-341 are: West Oil (22.5%), Apache Energy (22.5%), Tap Oil (operator 50%), Strike Oil (5%). West Oil acquired its 22.5% interest from Apache.

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1000 PCs Work Their 'Magic' 3D Solution

Shell scientists have achieved a breakthrough with a new technique to improve the seismic images used in oil and gas exploration.

MAGIC3D, developed by Shell geoscientist Jan Biersteker, has generated a strong interest in the oil business because it addresses the problem of multiple reflections.

"These reflections occur because the sea surface acts as an almost perfect acoustic mirror creating multiple seismic echoes that can fully obscure the echoes from oil and gas reservoirs", Biersteker said. "These multiple reflections make the interpretation of seismic images extremely difficult or impossible."

The MAGIC3D technology was selected recently by a consortium of major oil companies to enhance the seismic data from the Ormen Lange field, one of Norway's largest deep water gas fields. MAGIC3D runs on Shell's large computer clusters with a 1500 km2 3D survey keeping 1000 computers busy around the clock, reworking terabytes of data.

Processing coordinator, Rob Eppenga, said the improvements in the images were spectacular and would lead to better field development decisions and potentially large savings.

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Park Road Group Expands

The Park Road Group has expanded and now consists of MBA Petroleum Consultants, the Saros Group, Predrill Stresses International, Reservoir Solutions, Action Resource Consultants, CDX-IT and GeoSynthesis.

The average experience of the consultants within the Group is 20 years at senior management levels. The Park Road Group is located at 2 Park Rd, Milton, Brisbane. Phone numbers: MBA 07 3367 3822, Saros 07 3367 3400, PSI 0407 440 949, RS 07 3367 3891, ARC 07 3367 3833, and GeoS 07 3367 3833.

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Six New Permits For WA Waters

Six new exploration permits in the Carnarvon, Perth and Browse basins have been issued in Commonwealth waters off the West Australian coastline.

Federal Resources Minister, Ian Macfarlane, said the six-year permits would lead to an expected expenditure of about $84 MM. "Further exploration of these areas is essential to deliver the competitive and reliable energy supplies essential to the future of Australia," Macfarlane said.

"The exploration programmes proposed in these permit areas will significantly advance our understanding of this strategically important energy resource. The granting of these six permits is a welcome indication that Australia continues to fight the world-wide decline in petroleum and gas exploration rates." The permits have been awarded as follows:

Permit WA-334-P in the Carnarvon Basin (originally released as area W02-13 in the Barrow Sub-basin) was awarded to Apache North West Pty Ltd (80%, operator) and Tap (Harriet) Pty Ltd (20%), which proposed a guaranteed programme for the first three years of one well and geoscience studies at an estimated cost of $5.45 MM. The companies also propose a secondary programme of one well and geoscience studies at an estimated cost of $4.1 MM. The permit was awarded on December 17th, 2002. There was one other bid for the area.

Permit WA-335-P in the Carnarvon Basin (originally released as area W02-15 in the Exmouth Sub-Basin was awarded to Apache North West Pty Ltd (100% operator), which proposed a guaranteed programme for the first three years of 550 km2 3D seismic survey, 1050 km 2D seismic survey, one well and geoscience studies at an estimated cost of $26.5 MM. The company also proposed a secondary programme of one well and geoscience studies at an estimated cost of $16 MM. The permit was awarded on December 17th, 2002. There were no other bids for the area.

Permit WA-336-P in the Perth Basin (originally released as area W01-20) was awarded to Petroz NL (100%, operator), which proposed a guaranteed programme for the first three years of 1225 km 2D seismic survey, purchase of additional 1364 km 2D seismic survey and geoscience studies at an estimated cost of $2.4 MM. The company also proposed a secondary programme of one well, 500 km 2D seismic survey and geoscience studies at an estimated cost of $13.85 MM. The permit was awarded on December 18th, 2002. There was one other bid for the area.

Permit WA-337-P in the Perth Basin (originally released as area W01-26) was awarded to Kerr-McGee NW Shelf Australia Energy Pty Ltd (100%, operator), which proposed a guaranteed programme for the first three years of 1100 km 2D seismic survey and geoscience studies at an estimated cost of $2.3 MM. The company also proposed a secondary programme of 1000 km 2D seismic survey and geoscience studies at an estimated cost of $2.2 MM. The permit was awarded on January 15th, 2003. There were no other bids for the area.

Permit WA-338-P in the Browse Basin (originally released as area W01-5) was awarded to Santos Offshore Pty Ltd (71.5%, operator) and the Korea based SK Corporation (28.5%), which proposed a guaranteed programme for the first three years of 350 km 2D seismic survey and geoscience studies at an estimated cost of $1.55 MM. The companies also proposed a secondary programme of one well and additional geoscience studies at an estimated cost of $4.4 MM. The permit was awarded on January 15th, 2003. There were no other bids for the area.

Permit WA-339-P in the Perth Basin (originally released as area W01-21) was awarded to Santos Offshore Pty Ltd (50%) and Kerr-McGee NW Shelf Australia Energy Pty Ltd (50%), which proposed a guaranteed programme for the first three years of 1000 km 2D seismic survey and geoscience studies at an estimated cost of $2.6 MM. The companies also proposed a secondary programme of 1000 km 2D seismic survey and geoscience studies at an estimated cost of $2.6 MM. The permit was awarded on January 15th 2003. There was one other bid for the area.

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BHPB And Woodside Strike Oil Near Exmouth

BHP Billiton and Woodside Energy made an oil discovery at the Stybarrow-1 exploration well (WA-255-P), 55 km northwest of Exmouth, in the Exmouth sub basin on February 25th. The well encountered a gross oil column of 23 m with 18.6 m of net pay in the Macedon Member sandstone reservoir after reaching a measured depth of 2,477 m. Water depth was 825 m.

A BHP Billiton statement said the significance of the well will be assessed following further evaluation of drilling results, and appraisal drilling will be necessary to determine the size of the find. "The discovery is in an area where there has been a number of discoveries made by the industry", the statement said.

"Development planning studies would not be completed until after further appraisal and exploration activity in the permit." The Stybarrow-1 well is 14 km west of Woodside's Enfield discovery and 4 km northwest of its Laverda discovery.

Woodside recently acquired a 50% interest in the Stybarrow-1 exploration well. Woodside's Australian Oil Director, Keith Spence, said Woodside selected the permit for attention because it provided access to highly prospective exploration acreage near the Enfield area development.

Drilling on Stybarrow-1 commenced on February 12, 2003 using the Atwood Falcon semi-submersible drilling rig. Stybarrow-1 is the first well in the current exploration programme in WA-255-P. The Eskdale-1 well, located approximately 13 km north of Stybarrow-1, will also test the Macedon Member sandstone reservoir but in a different trap configuration to Stybarrow-1.

BHP Billiton owns a 50% interest and is the operator of WA-255-P with the other 50% held by Woodside Energy.

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Timor Sea Treaties Pave Way For Huge Gas Projects

The Australian and East Timor governments have finally ratified the Timor Sea Treaty and signed the International Unitisation Agreement (IUA), in March, paving the way for the development of the Bayu Undan and Greater Sunrise gas fields.

Federal Resources Minister, Ian Macfarlane, said the agreements would deliver operational certainty for the Bayu Undan and Greater Sunrise joint venture partners, which he said had been: "loudly chomping at the bit to jump into these rich reserves."

"With goodwill on both sides, the governments have delivered and it's now time for these companies to step up to the line", Macfarlane said. "From this point forward I expect gas marketing, final development plans and construction to be their highest priorities. I will assist with marketing of gas however I can, particularly during my upcoming visit to China, Korea and Japan. But let me be absolute - get over the commercial wrangling and get on with the job. This is the line in the sand."

The Timor Sea Treaty, which covers the Elang/Kakatua, Jahal and Krill oil fields, as well as the Bayu Undan, Kelp and Hingkip gas fields, was passed by the federal government on March 7th. These fields fall within the agreed Joint Petroleum Develop-ment Area, shared by Australia and East Timor. The Bayu Undan gas and liquids field is located in the Timor Sea, 500 km northwest of Darwin. Total revenue from the full development of Bayu-Undan is estimated to exceed $30 BB.

Santos Managing Director, John Ellice-Flint, welcomed the ratification of the Timor Sea Treaty, saying it was a further milestone in the future development of the liquefied natural gas (LNG) stage of the Bayu Undan project. "The passage of this legislation is an important step towards the commercialisation of Bayu-Undan gas reserves, to the benefit of both East Timor and Australia", he said.

"Following the project ramp-up, LNG production net to Santos would be over 3 MMboe per annum.

Approximately 50 MMboe of probable gas reserves would be moved to proven reserves. We look forward to working with all stakeholders to bring this important project to fruition", he said.

Current interests in the Bayu-Undan project are: ConocoPhillips (operator and 64.14%), Santos Group (11.83%), AGIP (12.32%), Inpex (11.71%).

The IUA for the Greater Sunrise gas field, estimated to contain almost 8.5 tcf of natural gas, was approved on March 6th. The total value of the field is estimated at $60 BB. Development of the field could see exports in excess of $1.5 BB to Australia, annually. The Greater Sunrise reserve straddles the border between the Joint Area and Australian waters, with 79.9% falling within the Australian jurisdiction and 21.1% in the Joint Area.

Woodside Energy's Gas Business Unit Director, David Maxwell, said the agreements have set the legal and financial framework under which Woodside and its joint venture partners would seek to develop the Greater Sunrise gas fields and Kuda-Tasi and Jahal oil discoveries.

"Woodside is now focused on working with its Sunrise joint venture participants on pursuing customers and commercial arrangements to support development of the Greater Sunrise gas fields", Maxwell said.

The Sunrise joint venture partners are: Woodside (operator and 33.44%), ConocoPhillips (30%), Shell (26.56%) and Osaka Gas (10%).

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No New Projects For Burrup

The Western Australian government has decided not to allow any new major projects to be established within the Burrup Industrial Estate and is looking at new locations within the Pilbara for alternative sites.

State Development Minister, Clive Brown, said land available to major projects within the Burrup Industrial Precinct had been fully allocated. Options being considered include the Maitland Estate, West Intercourse Island, Cape Lambert, Boodarie and Onslow.

A total of eight projects, including the Burrup Fertilisers plant, are earmarked for the Burrup. Brown said the current land allocation was consistent with the Burrup Peninsula Land Use Plan and Management Strategy 1996 which set aside 62% of the Burrup for conservation and heritage purposes, and the remaining 38% for industrial purposes.

Brown said that in the event of a project's land allocation expiring, the government would seek to reallocate the land to a new project, in consultation with the Shire of Roebourne. This would ensure the WA public would receive maximum value from the government's investment in multi-user infrastructure.

He said while land available to major projects within the Burrup Industrial Precinct had now been allocated, some land would be required by infrastructure and less intensive downstream, strategic and support industries. Such smaller scale developments would occur within the 38% of the Burrup currently set aside for industry.

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