Australia’s oil self-reliance may falter without new discoveries

March 6, 2006
Australia gradually is slipping behind in its attempts to maintain self-sufficiency in oil despite a rally during 2005-06 as a result of new on-stream production, principally from Mutineer-Exeter field and the coming Enfield development, both in the Carnarvon basin off Western Australia.

Australia gradually is slipping behind in its attempts to maintain self-sufficiency in oil despite a rally during 2005-06 as a result of new on-stream production, principally from Mutineer-Exeter field and the coming Enfield development, both in the Carnarvon basin off Western Australia. The country’s total expected crude oil and condensate production rate for 2006 is about 560,000 b/d, up from 460,000 b/d recorded for 2005.

This will be an improvement on the 490,000 b/d recorded for 2004 but still well behind the peak production of over 800,000 b/d in 2000.

Unfortunately, the current holding pattern is unlikely to last, as there have been no significant oil discoveries in the past 18 months. If this lack of exploration success continues, the nation’s self-sufficiency in liquid petroleum could fall to about 50% by 2010, a marked contrast to the 95% in 2000.

Downstream, Australia’s total refining capacity remains at about 770,000 b/d. All seven of the country’s main refineries have spent large sums to comply with stringent new federal environmental standards for reducing sulfur and benzene content in fuel.

Nevertheless, the refineries are relatively small and are finding it increasingly difficult to compete with cheap gasoline imports from Asia.

In addition, ExxonMobil Corp. closed its Port Stanvac plant in Adelaide in 2003, and there is continuing speculation about the possible closure of another refinery before the end of the decade.

Better news is that natural gas discoveries and production are steadily increasing. Three main finds in 2005-Pluto and Hurricane in Carnarvon basin and Caldita in the Timor Sea-have recorded substantial gas accumulations. At the same time, most of the development projects brought on stream in the last 12 months and those still under construction are gas fields for both domestic consumption and for export as LNG.

Total gas production forecast for 2006 is expected to reach 45.5 billion cu m, up from 41.2 billion cu m last year. LNG production of 10.6 million tonnes/year in 2005 (about 40% of Australia’s total gas production) is expected to rise to over 13 million tonnes in 2006 with the ConocoPhillips Darwin plant now on stream.

Australia’s gas scene is also enhanced by an increasing supply of coalbed methane (CBM), mostly from projects tapping the Surat and Bowen basin coal measures in southeast Queensland. CBM now supplies 30% of Queensland’s gas demand.

Exploration

The bulk of Australia’s exploration activity over the last 12 months has been off western and northern Australia. Elsewhere, lesser contributions have come from the offshore Otway and Gippsland basins off Victoria and onshore provinces of the Perth, Cooper-Eromanga, and Surat basins of Western Australia, South Australia, and Queensland.

Offshore

A significant discovery in 2005 was Woodside Energy Ltd.’s large Pluto gas find in Carnarvon basin Permit WA-350-P some 190 km off Western Australia. Within a few months of this March 2005 discovery, the company had canvassed the possibility of a $5 million (Aus.) two-train LNG development, received “major project facilitation” status from the federal government, and signed a provisional 15-year deal with Tokyo Gas Co. Ltd. to supply 1.5-1.75 million tonnes/year of LNG beginning in 2010. Tokyo Gas also took 5% in the project. Front-end engineering and design work has begun. To meet the proposed on-stream target, a final investment decision will be needed in mid-2007.

Three gas-condensate wells are produced from this unmanned platform in John Brookes field on the North West Shelf off Western Australia. Gas is delivered via a 55-km pipeline to Varanus Island production facilities. Photo courtesy of Apache Corp.
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Equal interest came with the discovery of Caldita gas field in Permit NT/P61 in the eastern Timor Sea by partners ConocoPhillips and Santos Ltd. in September 2005. The find, about 265 km north-northwest of Darwin in 137 m of water, tested gas at 33 MMcfd, including an unspecified amount of carbon dioxide. Knowing it to be a southerly extension of Shell Development (Australia) Pty. Ltd.’s 1960s Lynedock gas find, ConocoPhillips and Santos quickly applied for and won the open Lynedock area and plan a renewed exploration program in the next 12 months. Both companies are members of the Bayu-Undan gas development and are eager to find sufficient gas supplies to add a second and perhaps a third train to the associated Darwin LNG facilities.

Santos, this time as operator, also figured in the Hurricane gas discovery in Permit WA-208-P in January 2005. The well encountered a 76 m gross gas column, but post-well evaluation has shifted the focus to a potential underlying oil column. Hurricane is near Woodside Energy Ltd.’s producing Legendre oil field, and the Hurricane-2 appraisal is to be drilled in 2006, depending on rig availability.

The quiet achiever of 2005 was the Apache Energy Group (Apache Corp., Houston; Kufpec Australia Pty. Ltd., Perth; and Tap Oil Ltd., Perth), which continued to add small, but significant oil fields to feed into its Varanus Island oil and gas facilities in the Carnarvon basin. Drilling from and near existing platforms, the group made four oil discoveries at regular intervals during the year at Albert-1, Remus-1, Mohave-1, and Artreus-1. All were quickly tied into the Varanus production system and tanker loading facilities.

Exploration activity off southeastern Australia during 2005 was the highest it had been for some years, particularly in the Gippsland basin where a number of small explorers have taken up acreage near the main ExxonMobil-BHP Billiton Ltd. producing area. Drilling results have not matched enthusiasm, although groups led by other Melbourne companies Bass Strait Oil Co. and Nexus Energy Ltd. plan to continue drilling in 2006. Nexus, in particular, wants to appraise its Longtom gas field in Permit Vic/P54 with Longtom-3 in midyear. The company is confident of a commercial development and has already arranged with Santos to send a potential 350 PJ of gas through Santos’ existing Patricia-Baleen gas plant on the coast near Orbost over a 10-year period.

Better exploration success came to the Woodside group (Woodside, Origin Energy Resources Ltd., Sydney; Benares International NV; and CalEnergy (Australia) Ltd.) and the Santos group (Santos, Australian Worldwide Exploration Ltd., (AWE), Sydney; and Japan’s Mitsui & Co. Ltd.) in the Otway basin off western Victoria. The former made gas discoveries at Black Watch-1 and nearby Hallidale-1 during 2005. Both wells were drilled from the same location. The Santos group found gas at Henry-1, which is close enough to Casino gas field to make an easy production tie-in. Santos currently is evaluating the potential.

Onshore

The best onshore exploration results still come from the Cooper-Eromanga basins of South Australia, where a number of small companies are working near the Santos-held production hub. Explorers such as Beach Petroleum NL, Adelaide; Cooper Energy Ltd., Perth; Stuart Petroleum Ltd., Adelaide; Victoria Petroleum NL, Perth; Great Artesian Oil & Gas Ltd., Sydney; and Innamincka Petroleum Ltd., Brisbane, have all made small oil and gas discoveries in the past 12 months. High oil prices and extensive infrastructure in the region have enabled these discoveries to be brought on stream relatively quickly.

Santos also increased its exploration effort and recently began a 4-year, 1,000-well drilling program in its Cooper-Eromanga acreage in South Australia and Queensland. The target is a potential 75 million bbl of oil, which the company believes remains in existing and undrilled structures.

Elsewhere in the country, the partnership of Arc Energy Ltd., Perth, and Origin Energy continued its successful run with three gas finds (Corybus, Tarantula, and Senecio) in the onshore Perth basin during 2005. In the Surat-Bowen basin of Queensland, Mosaic Oil NL, Sydney, found Permian oil in its Rockhampton High prospect, and Sunshine Gas Ltd., Brisbane, Queensland, found gas at Champagne Creek. Evaluation work on both discoveries will continue this year.

Onshore exploration activity will move a little more outside the norm in 2006. Empire Oil & Gas NL, Perth, plans to drill the Dune-1 wildcat near Australia’s original 1953 Rough Range oil discovery near Exmouth in Western Australia, while newcomer Central Petroleum Ltd. is tackling new targets in the Pedirka and Amadeus basins in Northern Territory. Melbourne-based Lakes Oil NL is pressing on with exploration of tight gas sands in the extensive Cretaceous-age Strzelecki Group sediments of Victoria’s onshore Gippsland basin and, in a real frontier effort, Sydney-based Eastern Star Gas Ltd. is planning several wells in the virtually untouched Darling basin of western New South Wales.

Development

Development activity has been a major Australian petroleum industry focus during the last 12 months, and it will continue in that vein as projects in the planning and construction stages are brought on stream during the next 4 years.

On-stream oil

Bright lights in the oil business have been Santos group’s Mutineer and Exeter fields in the Carnarvon basin, which were brought on stream in March 2005 at 72,000 b/d. The $440 million development-by Santos, Kufpec, Nippon Oil Exploration (Dampier) Pty. Ltd., and Woodside-consists of four subsea wells tied to a floating production, storage, and offloading (FPSO) vessel in about 150 m of water. The facilities have been designed for a plateau production of 100,000 b/d.

Another key oil development to begin production in 2005 was the Basker-Manta complex in the Gippsland basin off Victoria, which Anzon Australia Ltd. and Beach Petroleum are developing. The $260 million project is notable for its rapid development-12 months from design concept to first oil-and for its use of the first FPSO in Bass Strait. The Basker-2 appraisal-production well brought Basker field on stream in November 2005, producing 8,000 b/d from a subsea wellhead connected to the 40,000-bbl-capacity Crystal Ocean FPSO. Basker Spirit, a larger storage-offloading tanker, delivers the crude to market.

A well on nearby Manta field was completed in February. It, along with two more production wells at Basker, will be brought on stream in midyear to increase total production to 20,000-25,000 b/d. After separation from the oil stream, Manta’s associated gas will be stored in Basker field in a purpose-drilled reinjection well.

Anzon and Beach are evaluating the potential for a separate project in the region to commercialize the gas, a development that would include Gummy, a third primarily gas field. All three fields were found by Shell during 1983-90.

Onshore oil development saw a revival of Australia’s 1953 oil discovery at Rough Range near Exmouth in Western Australia. Empire Oil & Gas NL, Perth, began producing oil on pump at 125 b/d in July 2005. Oil is trucked to BP PLC’s refinery at Kwinana, south of Perth. Other small oil fields brought on stream during 2005 included Mosaic Oil’s Waggamba in the Surat basin, Great Artesian Oil & Gas’s Kiana, and Victoria Petroleum’s Ventura in the Cooper-Eromanga basins.

On-stream gas

Two major gas fields coming on line in the last 14 months were Apache Energy-Santos’ $300 million John Brookes field on the North West Shelf in September 2005 and ConocoPhillips group’s $2 billion LNG development using feedstock from Bayu-Undan field in the Timor Sea in February.

Three wells produce in John Brookes to an unmanned platform and move from there into a two-phase, 55- km pipeline to Apache’s production facilities on Varanus Island. Flow rate is around 180 TJ/day of gas plus 850 b/d of condensate. Sales gas is sent to the mainland to connect with the main Dampier-to-Bunbury trunkline.

The larger Bayu-Undan project (ConocoPhillips, Eni SPA, Tokyo Gas, Tokyo Electric Power Co. Inc., Santos, and Inpex Corp., Tokyo) is sending gas southeast via a 500-km pipeline to the new 3.4 million tonne/year LNG plant at Wickham Point near Darwin. Condensate is stripped out at the field and delivered to an FPSO and offloading tankers. Tokyo Gas and Tokyo Electric Power have contracts to take 3 million tonnes/year of LNG over 17 years. This leaves room for the ConocoPhillips group to sell occasional cargoes in the spot market. The group has approval to extend the plant capacity to 10 million tonnes/year and is seeking additional gas supplies in the Timor Sea.

Elsewhere, the offshore Otway basin of western Victoria joined the ranks of Australia’s gas producing regions in January 2005 when BHP Billiton-Santos’ $225 million Minerva field development was brought on stream at 150 TJ/day plus 600 b/d of liquids. The Santos group followed in February of this year, bringing its $200 million Casino field at 96 TJ/day plus liquids.

Each field, in about 65 m of water, is producing from two subsea wells connected via subsea pipelines to discrete onshore production facilities near the coast.

The pipelines (10 km long for Minerva and 30 km long for Casino) were directionally drilled under the coastal cliffs to preserve the region’s environmental integrity. Gas is sold into trunklines serving the South Australian and Victorian markets.

Under construction

Development projects still under construction are mostly concentrated off Western Australia, and Woodside Energy is the dominant participant.

Closest to completion is Woodside and Mitsui’s $1.4 billion Enfield oil development in the Carnarvon basin, due on stream this year at 100,000 b/d. Production will be from five subsea wells tied in to an FPSO in 600 m of water. The field is off Western Australia 50 km northwest of Exmouth.

Three additions to the original North West Shelf Gas Project will come on line in stages until yearend 2008. The $700 million Perseus-over-Goodwyn project involves three subsea wells in Perseus field being tied by pipeline to the nearby Goodwyn platform production facilities.

Gas and condensate will be piped to the North Rankin platform and from there to the onshore Burrup Peninsula plant. Perseus production will be added gradually as capacity on the Goodwyn platform allows.

The $1.6 billion Angel field production is due on stream in 2008, finally bringing gas to the Burrup plant from the third original North West Shelf field found in 1972. An unmanned platform will produce from Angel, with deliveries via a 50-km pipeline tying in to one of two trunklines from North Rankin to the coast.

A tugboat tows production facilities for Bayu-Undan gas field in the Timor Sea Joint Petroleum Development Area shared by Australia and East Timor. The field, now producing, will provide sales gas to the Australian mainland and feedstock for as much as 10 million tonnes/year of LNG. Photo courtesy of ConocoPhillips.
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To accommodate increased gas flow and fulfill LNG export and domestic pipeline gas supply contracts, the Woodside-led North West Shelf partnership has begun a $2 billion program to add a fifth LNG train at the Burrup Peninsula liquefaction plant. With a planned capacity of 4.4 million tonnes/year, the train will increase total plant capacity to 16.3 million tonnes of LNG when it comes on stream at yearend 2008.

Woodside also is a 50:50 partner with BHP Billiton (operator) for the $800 million Stybarrow oil project in the Carnarvon basin 65 km northwest of Exmouth. Stybarrow lies in 800 m of water and will produce 80,000 b/d via subsea wells and an FPSO. Oil production will begin in 2008.

Farther south, oil production from the offshore Perth basin will begin in March-April when the Roc Oil Ltd. consortium’s $227 million Cliff Head field development comes on stream. Partners are Roc Oil, Sydney; AWE; Wandoo Petroleum Pty. Ltd.; Arc Energy; and Cieco Exploration & Production (Australia) Pty. Ltd. The unmanned wellhead platform was installed in 18 m of water, 11 km offshore, in December 2005. Oil will be sent via subsea pipeline to a new onshore production facility at Arrowsmith near Geraldton before being trucked 350 km to BP’s Kwinana refinery south of Perth. Initial production will be 10,000 b/d.

In the Timor Sea southwest of Jabiru field, AED Oil Ltd., Melbourne, is developing its 100%-owned Puffin oil field in Ashmore Cartier Permit AC/P22. ARCO discovered Puffin in 1972-the first oil found in the Timor Sea-but it was not then considered commercial. AED plans a $100 million, two-well subsea development hooked into an FPSO and flowing at about 25,000 b/d when it comes on stream in midyear.

Woodside Energy (with Origin Energy, Benaris International, and CalEnergy) also expects its Thylacine-Geographe gas fields in the offshore Otway basin to come on stream by midyear. This $1 billion project includes a remotely operated, unmanned platform on Thylacine and a subsea pipeline to onshore treatment facilities near Port Campbell on Victoria’s coast. Geographe field will have subsea wells tied in to the Thylacine system later. The sales gas will be injected into the South Australian-Victorian pipeline system.

Another offshore gas project nearing completion in southeastern Australia is Yolla field in the Tasmanian Bass basin being developed by the Origin Energy consortium (Origin, AWE, CalEnergy, and Wandoo Petroleum). Construction and equipment problems have pushed costs to more than $500 million, and the project is more than 12 months behind schedule. Now expected on stream in March, the development consists of a fixed steel platform and a 147-km subsea pipeline to the Victorian coast plus a 32-km onshore section to a gas treatment plant at Lang Lang about 80 km southeast of Melbourne. Sales gas will be sent by another 30-km pipeline to connect with Victoria’s main gas trunkline from Gippsland basin fields.

Preliminary design work also has begun on the $300 million Kipper gas-condensate field development in Gippsland basin. Operated by ExxonMobil, the field straddles retention lease Vic/RL2 and production license Vic/L9. The consortium includes BHP Billiton, Woodside, and Santos. Plans include subsea wells and associated pipelines to feed into the main ExxonMobil-BHP Billiton Bass Strait production system via West Tuna field’s platform. First gas is expected in 2009.

Imminent projects

The most talked-about proposal is the Greater Gorgon Project, the Chevron group’s $11 billion Gorgon gas-condensate development 130 km off Western Australia. The plan was restructured in early 2005 to include nearby ExxonMobil-operated Jansz field, and the framework agreement gave Chevron 50% of the project, while ExxonMobil and Shell have 25% each. The proposal is for separate development of the two fields, with two pipelines feeding into two LNG trains on Barrow Island, each with 5 million tonnes/year of capacity. Gorgon field has a 12% carbon dioxide content, which will be separated on Barrow and sequestered in a reservoir sand deep under the island.

Chevron has signed letters of intent to sell 1.5 million tonnes/year of LNG to Osaka Gas Corp. and a total of 2.7 million tonnes/year to Tokyo Gas and Chubu Electric Power Co. Inc. Shell is reported to be negotiating the sale of 14 million tonnes of LNG over 20 years with Indian company Gujarat State Petroleum Corp., but ExxonMobil has yet to make any public statement.

The project moved to the front-end engineering and design stage last July, and a financial decision will be made at the end of 2006. Approval will set 2010 as the target date for first LNG production.

Two other major LNG projects being discussed are Woodside’s Pluto field development and the Woodside-operated Browse basin field proposal, which includes the original North West Shelf partners BP, BHP Billiton, Chevron, and Shell. Driven by Woodside, the plan revolves around the huge Torosa (formerly called Scott Reef) and Brecknock gas-condensate fields, found in the 1970s, and Calliance field (formerly Brecknock South), found in 2000, all 400 km off Western Australia’s northwestern coast.

Two successful appraisal wells were drilled in 2005, and four more will be drilled in 2006. Total gas reserves are estimated at 20 tcf with 300 million bbl of condensate. Preliminary development calls for a pipeline to a liquefaction plant at Broome on the Western Australia coast, with first production during 2011-14.

A number of other offshore projects are under study. These include the BHP Billiton-ExxonMobil 1979 Scarborough gas discovery on the Exmouth Plateau in which BHP is the driving force. The company hopes to bring gas ashore to a proposed LNG plant at Onslow, Western Australia. It would sell the LNG to the US, delivering to its proposed Cabrillo Port regasification plant off California.

Eni wants to develop its 100%-owned Blacktip gas field in the Bonaparte Gulf via a pipeline across Northern Territory to Darwin, where it has made an in-principle 25-year gas supply agreement with Northern Territory Power & Water Corp.

Nexus Energy bought 100% of Crux gas-condensate field in the western Timor Sea in September 2005 and is evaluating plans for a liquids-stripping operation and FPSO development.

An intriguing concept is the Tassie Shoals artificial island LNG and methanol proposal in the Timor Sea planned by Methanol Australia Ltd., Melbourne. The methanol plant is a 50:50 partnership with Air Products & Chemicals Inc., Allentown, Pa., while the LNG project is 100% Methanol Australia’s at this stage. Initial plans revolve around gas supply from the Santos’ large Evans Shoal gas field 12 km away to feed the plants, which will be built on concrete islands set on the seafloor in about 70 m of water. Methanol Australia has exploration prospects of its own in adjoining acreage and hopes that a drilling campaign this year will be successful enough to supply both plants.

The most questionable Australian project at present is Woodside group’s Greater Sunrise gas fields straddling the joint development zone between Australia and Timor-Leste in the eastern Timor Sea. Some $250 million has been spent on appraisal drilling and feasibility studies that include piping gas to the new Wickham Point LNG plant near Darwin. However, the project has been put on hold until partners Woodside, ConocoPhillips, Shell, and Osaka Gas receive legal, regulatory, and fiscal certainty from Timor-Leste and Australia. Both governments signed an accord over 50:50 division of royalties from the field in January, but this has yet to be ratified by the parliaments of either country.

Pipelines

All of Australia’s development projects and concepts involve long-distance pipelines or shorter gathering lines to FPSO production facilities. However, the major independent pipeline project under discussion is the ExxonMobil-operated PNG-Australia trunkline proposal to bring gas from Papua New Guinea highland fields across Torres Strait to Australia with landfall in Queensland.

The 3,000-km pipeline will be built and owned by Australian Gas Light (AGL) and Malaysia’s Petronas. It will have possible offshoots to an alumina plant in northeastern Northern Territory and a link from Townsville on Queensland’s east coast to Ballera in southwestern Queensland. The latter link would enable gas to flow from Papua New Guinea to southeastern Australia through existing interstate networks.

The ExxonMobil group has conditional sales agreements totaling 230 PJ/year with CS Energy Ltd., Brisbane; AGL; Queensland energy distributor Energex; and Alcan. Feed studies for the project’s pipeline and upstream sectors are nearing completion, and a final investment decision is expected in the second half of this year. If approval is given, first gas is expected in Australia during 2009.

In other trunkline activity, work has begun on a $430 million project to expand carrying capacity of the Dampier-Bunbury natural gas line in Western Australia by 100 TJ/day. The project involves installation of eight compressor units and looping of 200 km of pipeline.

Downstream

Main downstream projects over the last 2 years have involved Australia’s four oil refiners-Caltex, Shell, BP, and ExxonMobil-in clean fuel developments. The companies have spent an average $400 million each in upgrading plants and equipment at the country’s seven refineries to comply with federal fuel specifications. This means manufacture of diesel fuel with a maximum of 50 ppm sulfur content (down from 500 ppm) and gasoline with a benzene content of no more than 1% (down from 3%).

Elsewhere, downstream proposals have not fared well. This is typified by the withdrawal in January of Plenty River Corp., Melbourne, from a $900 million ammonium plant project on Burrup Peninsula in Western Australia. The company cited a failure to secure gas feedstock supplies because of the priority being given to LNG projects. Several other ammonium and gas-to-liquids (GTL) proposals have failed to advance in Western Australia for similar reasons. The exception is a $630 million ammonium plant for Indian-owned Burrup Fertilizers, which is now nearing completion.

There is also a mini-LNG plant nearing completion at Karratha in Western Australia for Energy Developments Ltd. It will liquefy gas from offshore North West Shelf fields and truck the LNG northward to four gas-fired power stations in the state’s remote Kimberley district.

More-recent proposals include the possibility of a GTL plant in central Australia based on Amadeus basin gas discoveries and a $450 million condensate processing plant for Port Darwin, using feedstock from condensate associated with gas production in the Timor Sea. If approvals come through in 2006, construction of the latter plant could begin in 2007 for an on-stream date of 2009.