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Pipe in Pipe Technology
Australia poised as leading Asia-Pacific LNG supplier 2011

Total Takes Stake in Browse Basin Permit Offshore Australia Total 2/2/2007

Browse basin Nexus receives  permit 2006

Chevron makes significant natural gas find in Australia 8/18/10
Queensland southeastern Cooper basin  2006
Browse basin Royal Dutch Shell PLC 2006

Australia Nexus Accepts Shell's Offer AC/P23 permit
Great Artesian Suspends Cadenza-1 Gas Discovery Cooper Basin 11 MMcfd
Victoria Petroleum potential 23 mlb oil 2006
Casino gas field on stream off Victoria 2006
Carnarvon basin northwest Australia 2006

Tap Oil Makes New Oil Discovery with Amulet-1 Exploration Well 2006
Canning Basin Permit Empire O&G 7/06
Ichthys LNG Project Total Takes Stake
Australia EPA oppose Gorgon-Jansz LNG Gov override Perth basin in Western Australia OGJ 2005

Average Price of Natural Gas to Industry, 2002          One thousand cubic feet (1 Mcf) ~  1.05 GJ
Country    US$ per Gigajoule   Australia 3.24
United Kingdom 3.70    United States 4.21    France 4.47 Germany 4.49    New Zealand 4.79    Japan 9.71
1: Data are for 4th quarter 2002 or latest available
Source: International Energy Agency, Key World Energy Statistics, 2003
Australia LNG
Australia ’s natural gas reserves 90 trillion cubic feet
One Bcf ~ 1.05 petajoules
Liquefied Natural Gas (LNG)

Papua New Guinea to Queensland, Australia
3,600 km gas pipeli
Australia $420b worth of projects in pipeline
The Australian Pipeline Trust (APT)
Australian Gas Light (AGL) operated ty APT

Australia Eni developing Blacktip gas field
A new gas scheme was introduced in Queensland
coalmine methane use has increased substantially
CBM exploration and production
CBM drilling activity

Perth basin

Bonaparte Basin

Australia coalbed methan
Northern Territory
Condensate plant proposed

Gippsland basin
contains one gas field, Patricia/Baleen
Otway basin
Casino gas field on stream off Victoria
Otway_basin Map
Australia poised as leading Asia-Pacific LNG supplier
PRAMO’O KULKARNI, Editor World Oil JUNE 2011

With extensive offshore, coal seam and shale gas resources, Australia is poised to become a leading LNG supplier to Asia-Pacific markets.
The Asia-Pacific region is divided into nations of energy “haves” and “have-nots.” Japan and South Korea are highly industrialized nations with virtually no oil and gas resources. China and India have substantial energy resources, but without imports they will not be able to cope with the expected rise in energy demand due to population growth and rapid industrialization. Malaysia and Indonesia are the traditional energy “haves” in the region, but are suffering from production declines in their mature fields.
The emerging energy giant in the region is Australia. The country has estimated potential gas resources of 400 Tcf, a number that is expected to grow as exploration continues in frontier offshore conventional gas and onshore coal seam and shale gas plays. According to the Australia Petroleum Production and Exploration Association (APPEA), Australia’s annual gas production for domestic consumption grew during the 2000—2009 decade from 726 Bcf to 1,001 Bcf and annual LNG exports grew from 345 Bcf to 736 Bcf. The country currently ranks as the world’s fourth largest LNG exporter and aims to move up the ranks as mega-LNG projects such as Gorgon and Wheatstone begin production by 2015.

Australia’s western, northern and southern coasts have yielded relatively little oil but vast volumes of natural gas and condensate. The incentive for E&P projects is strong because of LNG exports to neighboring Asia-Pacific countries and domestic demand for low-carbon energy, which is expected to increase sharply with the implementation of a planned carbon tax in July 2012 and a cap-and-trade scheme soon after. (Only 9% of Australia’s current electricity generation is gas fired, compared with 80% from coal.) Offshore drilling extends from the North West Shelf to the Bass Strait in the south to the deepwater Timor Sea in the north, Table 1.

Exploration opportunities.
Australia’s Department of Resources, Energy and Tourism is the agency responsible for releasing new offshore petroleum acreage. The available acreage in the current release comprises 29 areas, located across nine basins in commonwealth waters offshore Western Australia, Victoria, the Northern Territory, the Territory of Ashmore and Cartier Islands, and Tasmania, Fig. 1. Round 1 of the 2011 release will close on Oct. 13, 2011, and Round 2 will closes on  April 12, 2012. Significant exploratory and development drilling is underway on all three of Australia’s coasts.
Many of the recent offshore discoveries have taken place in the Carnarvon basin, where Chevron is the leading leaseholder. In 2010, the company achieved nine significant discoveries in the area. The latest, announced in January, is the Yellowglen- 1 well in the WA-268-P permit in the greater Gorgon area, 250 km northwest of Onslow, with results indicating a gas column of 137 m. Yellowglen-1 follows two other recent greater-Gorgon discoveries, Satyr-1 and Achilles-1. Also in the Carnarvon basin, Woodside Petroleum announced on May23 that its Xerex- 1 well intersected 51 m of gas in the WA-34-L permit, 12 km east-southeast of its Pluto-1 discovery. The well reached a TD of 2,385 m.
In late May, Santos announced the discovery of an oil column of 18 m while drilling in the Finucane South field in the Carnarvon Basin. The oil discovery is located 7 km from the Fletcher oil field discovered in 2009 and 14 km from the existing oil production facilities at Mutineer Exeter. A number of development options are under consideration, including a subsea tie back to its FPSO servicing the Mutineer Exeter field, enabling first oil production from Finucane South and Fletcher by the end of 2013. In April, Santos announced that its Zola-1 exploration well in the WA-290-P permit in the Carnarvon basin had intersected over 100 m of net gas pay sands over a 400-m gross interval in the Mungaroo formation. The well is located 27 km southwest of Gorgon-1, with a water depth of 280 m. In the adjacent Browse basin, ConocoPhillips has begun exploratory and appraisal drilling as a follow-up to its Poseidon-1 and Poseidon-2 discoveries made in 2010.

Major projects.
Australia’s offshore E&P activity is centered on massive projects ranging from mature operations such as the North West Shelf and Bass Strait developments to LNG projects such as Gorgon, which are in the construction phase, and initial proposals such as Sunrise LNG, Fig. 2.

North West Shelf.
Woodside Petroleum has been operating the North West Shelf Venture for the last 27 years. The largest of Australia’s oil and gas projects, the North West Shelf delivers oil and gas from the fields in the Carnarvon basin on Australia’s northwest continental shelf for domestic use and LNG export. The central hub of the offshore gas production system is the North Rankin-A platform, located 135 km northwest of Karratha in 125-m water depth. The platform gathers gas and condensate from 22 wells in North Rankin field and seven in Perseus field. The platform has a daily production capacity of 51,000 tonnes of gas and 5,400 tonnes of condensate, with dry gas and condensate transported via a trunkline system to the onshore Karratha gas plant for processing.
In March 2008, the North West Shelf Venture partners approved funding for a North Rankin redevelopment project, which will access additional reserves by recovering remaining low-pressure gas and extend the field life to 2040. The project involves installation of the North Rankin-B platform, which will be connected by two 100-m bridges to North Rankin-A. North Rankin-B is scheduled for startup in 2013, at which time both platforms will be operated as a single integrated hub facility. The redevelopment scope also includes necessary tie-ins and refurbishment of the North Rankin-A platform.
The Karratha gas plant also processes gas and condensate from the Goodwyn-A platform, 23 km southwest of North Rankin-A, and the remotely operated Angel platform, 120 km northwest of Karratha. The Goodwyn platform gathers production from 25 wells with five injection wells and has a daily production capacity of 36,000 tonnes of gas and 11,000 tonnes of condensate. The Angel platform has a capacity for 800 MMcfd of raw gas and 50,000 bpd of condensate. Later this year, Woodside is planning to replace the FPSO Cossack Pioneer, which is moored 34 km east of the North Rankin-A platform. The FPSO gathers 140,000 bopd and 3,800 tonnes of gas from Cossack, Wanaea, Lambert and Hermes fields. The crude oil is offloaded via a flexible line to bulk tankers moored astern, while a pipeline exports LPG-rich gas from Cossack and Wanaea fields to the North Rankin-A platform, for transport to the Karratha gas plant.

Bass Strait.
Operated by ExxonMobil with BHP Billiton as its 50:50 partner, the Bass Strait development, off Australia’s southern Gippsland coast, consists of 2l offshore platforms and 600 km of subsea pipelines used to transport oil and associated gas to a processing facility in Longford. The fields have been producing oil and gas for more than 42 years. While the mature fields are suffering production declines, ExxonMobil is planning to increase production with the addition of the Marlin-B platform and Kipper subsea wells during 2011.
The Kipper-Tuna-Turrum project will gather production from Kipper, Tuna and Turrum fields, Fig. 3. Once online, Kipper is expected to produce 10,000 bpd of condensate and 80 MIMcfd of gas and Turrum will produce 11,000 bcpd and 200 MMcfd. Tuna, which has produced oil for many years, is being further developed to produce gas and associated liquids. Based on the results of a 3D seismic survey in 2001, ExxonMobil feels confident that it will discover smaller fields that could be commercialized due to their proximity to existing platforms, allowing continued Bass Strait production at least until 2030.

Commissioned in 2006 by ConocoPhillips, the Darwin LNG plant processes gas from Bayu and Undan fields in the Timor Sea, 500 km north of Darwin and 250 km south of Timor Leste. Part of a joint petroleum development area (JPDA) of Australia and Timor Leste, the 3.4-Tcf Bayu-Undan complex is connected via a 504-km pipeline to the Darwin plant, which has an LNG capacity of 3.24 million tonnes per annum (mtpa). The project enables Australia and Timor Leste to commercialize a common hydrocarbon resource within the JPDA.

Baker Hughes recently established an under-reaming run-length record for a challenging well in the Bayu-Undan development. The GaugePro XPR bit under-reamed 2,011 m while drilling to a total measured depth of 4,467 m. The interval was completed at a 64° tangent and achieved an average penetration rate of 21.4 m/hr. The run was completed 13% faster and drilled 21% farther than offset under-reaming intervals.

Japanese oil and gas company Inpex, in partnership with Total, operates Icthys field, located 850 km southwest of Darwin. The field has an estimated 12.8 Tcf of gas and 527 million bbl of condensate of proved and probable reserves. The proposed project consists of an offshore central processing facility above Icthys field connected to an LNG liquefaction and condensate plant in Darwin by an 805-km pipeline, the longest in the Southern Hemisphere. An FPSO would be used to store and offload condensate. A final investment decision (FID) is expected in the fourth quarter of 2011, with a timeline calling for construction to begin in 2014 and first LNG production in 2016.

Billed as the world’s largest LNG project, Gorgon has Chevron as the operator with ExxonMobil and Shell as minority partners. The project will utilize a subsea gathering system to develop the greater Gorgon-area gas fields, which hold an estimated 40-Tcf recoverable resource base. The fields are located west of Barrow Island and about 130 km off the northwest coast of Western Australia, in water depths ranging 656—4,265 ft, Fig. 4. The downstream component of the project calls for the construction on Barrow Island of both a three- train, 15-mtpa LNG plant and a domestic plant with capacity to provide 300 terajoules per day of gas to Western Australia via pipeline. Gorgon LNG will be offloaded via a 4-km-long jetty for transport to international markets. Earlier this year, Chevron signed agreements with Kyushu Electric and JX Nippon to sell 0.3 mtpa of Gorgon LNG to each company for up to 20 years beginning in 2015.
An innovative component of the LNG project is an A$2 billion carbon dioxide injection program. The plan is to separate the CO2 from the produced gas stream and inject it into a containment reservoir about 2.5 km beneath Barrow Island, thereby reducing Gorgon’s overall greenhouse gas emissions by about 40%. At full capacity in 2015, a CO2 injection volume of 3.4—4 mtpa is expected. The containment reservoir will be carefully monitored via surveillance wells and repeated seismic surveying. In mid-May, Chevron accepted delivery of the newly constructed semisubmersible Atwood Osprey, which will conduct development drilling during 2011 and 2012 in the Gorgon fields. The sixth-generation ultra-deepwater rig is capable of drilling in 8,000-ft water depth, Fig. 5.

Chevron’s Wheatstone LNG project will process gas and condensate from Wheatstone, Iago, Julimar and Brunello fields via a central processing platform. There, the gas stream will be dehydrated, compressed and sent via a 200-km subsea trunk line to the onshore gas plant at Ashburton North, in Western Australia. Following the Wheatstone discovery in 2004, Chevron began the FEED phase in August 2009.
Apache and the Kuwait Foreign Petroleum Exploration Company, an investment arm of the Kuwaiti government, recently signed agreements with Chevron to supply gas from Julimar and Brunello fields to Wheatstone LNG in exchange for equity stakes in the project. In April, Shell also joined the project as a gas supplier and equity participant. Chevron has sales agreements for Wheatstone LNG with utilities in Japan and Korea.

The latest Woodside LNG project is Pluto, which will process gas from Pluto and Xena gas fields, located in the Carnavaron basin about 190 km northwest of Karratha. Discovered in 2005, the fields are estimated to contain 4.8 Tcf of dry gas reserves and an additional 0.25 Tcf of contingent resources. The offshore platform has been installed in 85 m of water and is connected to five subsea wells.  The gas will be piped via a 180-km trunk line to the onshore facility, located between the North West Shelf gas plant and the Dampier port on the Burrup peninsula. The A$14 billion initial LNG train at the onshore gas processing plant is expected to come online in August with a production capacity of 4.3 mtpa. Woodside has completed FEED for two additional onshore trains.

Three planned development projects offshore Australia involve the use
of floating liquefaction (FLNG) to commercialize the produced gas:
Woodside’s Sunrise, Shell’s Prelude and GDF Suez’s Bonaparte.

BHP Billiton and ExxonMobil are in the early stages of making a conceptual decision about how to process gas from Scarborough field, which the two companies own in a 50:50 partnership. The options are to build a standalone onshore processing plant or to connect the gas production to Woodside’s Pluto platform.

A joint venture operated by Woodside plans to commercialize three gas and condensate fields in the Browse basin—Brecknock, Calliance and Torosa—located 400 km offshore the Kimberley region of Western Australia. The development concept calls for gas and liquids from these fields to be brought to an onshore LNG plant 60km north of Broome. Basis-of-design studies were completed in November, and the project has entered the FEED phase. Woodside expects to obtain primary environmental approvals, secure a land access agreement and complete FEED for the LNG plant by the end of 2011, with FID planned by mid-2012 and liquefaction of first gas from the Browse fields by 2017. The other JV participants are BHP Billiton, BP, Chevron and Shell.

BHP Billiton is in the execution phase of its Macedon gas project offshore Western Australia. The concept involves four offshore production wells supplying a wet gas pipeline to an onshore gas treatment plant to be constructed at Ashburton North. The gas plant will have a design capacity of 200 MMcfd. A sales gas pipeline will be connected to the Dampier-to-Bunbury gas pipeline for sale to the Western Australian gas market.

Devil Creek.
A greenfield development operated by Apache, the Devil Creek project consists of an unmanned production platform that will produce 100 MMcfd and 500 bcpd from Reindeer field, offshore Western Australia. The gas and condensate will be transported via a 120-km supply line to an onshore processing plant 40 km southwest of Dampier. The raw gas will be processed and then supplied into the Dampier to-Bunbury pipeline. Condensate from the gas stream will be shipped south via heavy tankers to Kwinana. Gas production is expected to commence during second half of 2011.

Sunrise LNG.
A consortium led by Woodside plans to use a floating liquefaction (FLNG) concept to commercialize gas from Sunrise and Troubadour fields, located in the Timor Sea north of Australia, at an estimated cost of A$14 billion. The fields are estimated to hold a combined 5.13 Tcf and 226 million bbl of condensate. The development concept must still be approved by the government of Timor Leste, which opposes the FLNG concept and instead wants the gas piped across the Timor trench to an LNG plant on the island nation’s southwest coast. The country is entitled to 20% of the gas that would be
developed. A preliminary field development plan will be submitted for regulatory approval prior to the FID. Woodside’s project partners are ConocoPhillips, Shell and Japan’s Osaka Gas.

FLNG is also the concept chosen by Shell to commercialize stranded gas from Prelude and Concerto fields in the Browse basin, located 475 km north-northeast of Broome. The company announced its FID on May 20 approving the 480-m x 75-m vessel, which will be moored in 250 m of water and will be capable of producing 3.5 mtpa of LNG. FEED is being conducted by a consortium of Technip and Samsung, and first production is planned for 2016. Once a field is depleted, the FLNG vessel will be able to relocate to another virgin field.

GDF Suez also plans to use an FLNG vessel to commercialize production from its Petrel, Tern and Frigate fields in the Bonaparte basin offshore northern Australia at a rate of 2 mtpa. The operator acquired 60% of the fields from Santos in August 2009 to create a 60:40 joint venture. The project is currently undergoing pre-FEED analysis with FID scheduled for 2014 and first production in 2018.

Operated by BHP Billiton with Apache as a partner, the Pyrenees project gathers oil production from Ravensworth, Crosby and Stickle fields in water depths ranging 170—250 m about 19 km off the North West Cape of Western Australia through a subsea development tied to the FPSO Pyrenees Venture. Thirteen subsea wells—nine horizontal producers, three water injectors and one gas injector—are connected via flow- lines to seven subsea manifolds. The project commenced production in March 2010 and has a field life expectancy of 25 years.
Aftermath of Montara oil spill.
Two years after a blowout at its Montara well in the Timor Sea resulted in an oil spill of at least 400 bpd lasting 74 days, PTTEP, a division of the Thai national oil company, has applied to drill two new exploration wells in commonwealth waters. The new wells would also be in the Timor Sea, one located about 600 km west of Darwin and the other 765 km northeast of Broome. Federal Resources Minister Martin Ferguson had earlier cleared PTTEP to continue its Australian operations after an independent review found it was on the path to achieving “good oilfield practice.” However, a decision by the Northern Territory Department of Resources to issue the permit is still pending.

The north-central region of Australia has several basins that provide opportunities for some oil and mostly gas and condensate production for scores of small, independent operators. As conventional gas is depleted, operators are targeting shale and coal seam gas opportunities in the region.

Cooper basin.
Australia’s leading oil and gas basin straddles the states of South Australia and Queensland. Active since 1965, the Cooper basin contains more than 190 gas fields and
115 oil fields on production. The output of about 820 gas wells and more than 400 oil wells is gathered at processing facilities at Moomba in South Australia and Ballera in Queensland via approximately 5,600 km of pipelines. Natural gas liquids are recovered via a refrigeration process in the Moomba plant and sent together with stabilized crude oil and condensate via pipeline to Port Bonython. Ethane is transported to Sydney via a dedicated pipeline and sales gas is shipped to Adelaide, Sydney and Brisbane via pipeline. The major operators include Santos, Origin Energy and Beach Petroleum.

Amadeus basin.
A sedimentary basin located primarily in the Northern Territory, the Amadeus basin includes the Mereenie oil and gas/condensate field, the Palm Valley gas/condensate field and the Dingo gas field. Magellan Petroleum, one of the basin’s operators, has begun feasibility work with Mustang Engineering to determine the economic viability of Mustang’s small- scale LNG technology at Darwin to monetize gas volumes from the Amadeus basin and the offshore Bonaparte basin fields.

Coal seam gas.
Australia’s coal seam gas resources (CSG, known as coalbed methane in other parts of the world) are located in the eastern states of Queensland and New South Wales. The Commonwealth Scientific and Industrial Research Organization (CSIRO), Australia’s national science agency, estimates the eastern region’s CSG resources at about 250 Tcf, primarily in the Surat and Bowen basins.
CSG exploration in a known coal seam begins with seismic acquisition to select sites in which to drill a series of core holes to identify prospective gas content. A pilot well program will consist of five to six well clusters with a temporary dam for storing produced water. If a pilot program is successful, production wells are drilled at about 1,000-m spacing. High-density polymer piping connects the wellheads to central gas processing and water treatment facilities. CSG exploration has been spurred by the Queensland government’s requirement that an increasing share of electricity in the state come from gas-fired generators (13% by 2005 and 15% by 2010, with an option to increase to 18% by 2020).

Operated by Santos, the Gladstone LNG project will involve supplying CSG from Santos’ eastern Queensland fields to a gas processing and liquefaction plant on Curtis Island near Gladstone. The plant will produce 7.8 mtpa of LNG through two liquefaction trains. Santos expects to support the first train from its own CSG reserves. The Gladstone project received environmental approval from the Queensland government in May 2010, and sales agreements were signed with Korea Gas Corporation and Total in December, clearing the way for the FID, which was made the following month.

Asia-Pacific LNG.
Origin Energy and 50% partner ConocoPhillips are also planning to convert CSG production to LNG at a liquefaction plant to be located near Laud Point on Curtis Island. Two trains at the Asia-Pacific plant, located near Gladstone, are expected to process gas from Surat and Bowen fields at a rate of 4.5 mtpa per year.

Arrow Energy has undertaken a project for the staged development of about 1,500 wells in its Surat basin acreage.  The resulting gas will be directed to the Queensland market and potentially as supply to the LNG plants proposed for Fisherman’s Landing at Gladstone and the Shell Australia LNG Project on Curtis Island.
The fulfillment of these LNG projects will require CSG operators to drill as many as 5,000 producing wells. Some operators are planning to drill multiple extended reach laterals from a single mother wellbore in order to reduce costs and environmental footprint.
A major problem associated with such a high volume of drilling is how to handle the water generated from dewatering the coal seams. Beginning in 2012, the Queensland government will no longer approve the use of evaporation ponds to store the produced water. As a result, operators are evaluating water recycling and reinjection options. To support the expected increase in CSG drilling and production, oilfield service companies are increasing their infrastructure in the region. Schlumberger recently opened three operating facilities in Queensland to provide cementing, fracturing, wireline logging and directional drilling services.

Shale oil and gas.
Exploration for oil and gas from shales is in its infancy in Australia. Initial exploration activity is taking place in the Cooper basin and the southern Georgina basin in the Northern Territory.
Beach Energy estimates potential shale gas in place to be 40—80 Tcf at its holdings in Petroleum Exploration License 218 in the Cooper basin. At its Encounter-1 well drilled in late 2010, the company found the target zone in the early Permian shale of the Rosneath, Epsilon and Murteree formations to be thicker than anticipated and gas saturated with no water. Located at depths ranging 2,300—3,500 m, the shale is 120—260 m thick. In January, Beach’s Holdfast-1 well also encountered thick shale. In June, the company will begin flow simulation of both the wells in preparation for the development of pilot production wells in 2012. Beach compares its target shale to the Barnett and Haynesville shale plays.
According to a November 2010 report by petroleum consultancy Ryder Scott, there are strong technical similarities between the lower section of the organic-rich Arthur Creek “hot oil” shale in the Southern Georgina basin and the unconventional oil targets within the Bakken shale in North America’s Williston basin, Fig. 6. PetroFrontier, a Canadian company, has acquired two phases of 2D seismic surveys in its 13.6 million-acre exploration permit. Based on seismic and petrophysical evaluation, the company is planning a four-well drilling program, including two horizontal extensions of existing wells to test the shale play.

After Brazil and West Africa, Australia is currently the most vibrant oil and gas sector in the world. Offshore operators are involved in projects to increase production from the mature North West Shelf and Bass Strait, participating in engineering and construction activities for mega-LNG projects, and advancing the exploration frontier in the deepwater Timor Sea as well as the onshore coal seam gas and shale plays. If the E&P activities continue at the current pace, Australia will rank as a leading gas producer and the world’s second largest LNG exporter by 2015.

Chevron makes significant natural gas find in Australia 8/18/10
Chevron Corp. has announced further drilling success in the Carnarvon Basin offshore Western Australia, Australia’s premier hydrocarbon basin. “In terms of net gas pay, Acme-1 is one of our most significant natural gas discoveries in Australia. As our ninth and largest offshore discovery in Western Australia in the last 12 months, it underscores the quality of our drilling program and our commitment to technical excellence and safe operations.”

The Acme-1 exploration discovery well is located in the WA-205-P permit area offshore Western Australia approximately 93 miles (150 km) from Onslow. Drilled in 2,880 feet (878 m) of water to a depth of 15,469 feet (4,715 m), the well encountered approximately 896 feet (273 m) of net gas pay.

George Kirkland, vice chairman, Chevron, said, “In terms of net gas pay, Acme-1 is one of our most significant natural gas discoveries in Australia. As our ninth and largest offshore discovery in Western Australia in the last 12 months, it underscores the quality of our drilling program and our commitment to technical excellence and safe operations.”

Jim Blackwell, president, Chevron Asia Pacific Exploration and Production, said, “We are realizing the opportunities we have as a leading lease holder in the Carnarvon Basin. We expect this discovery to help underpin potential expansion opportunities at the Wheatstone liquefied natural gas hub. Adding to our Australian portfolio progresses our long-term plans to build a leading natural gas business in Australia and the Asia-Pacific region.”

Chevron’s Australian subsidiary is the operator of WA-205-P and holds a combined 67 percent interest, while Shell Development (Australia) holds the remaining interest
Total Takes Stake in Browse Basin Permit Offshore Australia Total 2/2/2007

Total has signed an agreement with U.S.-based Apache to farm into the offshore AC/P37 permit in Australia's Browse Basin. Located around 200 kilometers off the northwestern coast in a water depth of approximately 200 meters, this permit covers an area of 4,415 square kilometers.

Total is acquiring an 80% interest in and will operate the lower levels of this permit, beginning at a depth of roughly 4,000 meters. Apache is retaining a 20% interest and holds a 100% interest in the upper levels.

The farm-in strengthens Total's presence in Australia's North West Shelf, where it has interests in nine permits, and in the Browse Basin in particular, where the Group has had a 24% interest in the WA-285P permit containing the Ichthys discovery since 2006. The Ichthys liquefied natural gas project is scheduled to come on stream early in the next decade.
Ichthys LNG Project Total Takes Stake
Total 8/31/2006

Total announces the signature of an agreement with Japanese energy company INPEX to acquire a 24% interest in Block WA 285-P, located in approximately 250 meters of water offshore northwestern Australia. The proposed transaction is subject to the approval of the Australian authorities in the near future.

INPEX currently owns a 100% interest in Block WA 285-P, which contains the Ichthys gas field, discovered in 2000. Six appreciation wells drilled between 2000 and 2004 confirmed the find's rich gas and condensate potential.

The Ichthys development plan consists of an integrated field/liquefaction facility scheduled to come on stream early in the next decade. The plant is envisaged to be built on an island in the Kimberley region, less than 200 kilometers from the field. INPEX recently filed documents with Australian federal and state governments to obtain environmental approval for the project, with a capacity envisaged above 6 million metric tons of LNG a year associated with 100,000 barrels per day of condensates and LPG, and which could be increased depending on confirmation of additional reserves and market demand.

Since the beginning of 2005, Total has acquired stakes in eight different offshore exploration blocks in Australia's North West Shelf. This latest transaction will considerably strengthen Total's presence in this area's gas industry.

The partnership between INPEX and Total dates back to 1970, when they began developing the Mahakam block in Indonesia, which supplies over 70% of the feed gas for the Bontang plant, one of the world's largest LNG facilities.

The latest venture with INPEX will support Total's expansion and diversification in LNG beyond 2010 by creating another major growth center in Asia.

A global LNG operator with equity sales amounting to 7.7 million metric tons in 2005, Total plans to grow LNG production by an average 12% a year to 2010. Since early 2005, Total has also signed agreements to develop or participate in three other major, long-term LNG projects: Yemen LNG, Qatargas 2 and, most recently, Brass LNG in Nigeria.
Canning Basin Permit Empire O&G 7/06
Empire Oil & Gas 7/7/2006

Empire Oil & Gas' subsidiary, Gulliver Productions Pty Ltd has been granted exploration permit EP 488 in the onshore Canning Basin in Western Australia. The new permit is effective from June 16, 2006 for an initial six year period and was previously application 14/00-1.

The EP 448 permit has an areal extent of approximately 16,800 square kilometers and is located in the central and western part of the onshore Canning Basin, southeast of the Great Northern Highway, an all-weather sealed road. The permit is 200-400 kilometers south of Broome and 300-500 kilometers east of Port Hedland.

The potential reservoir objective at the Ordovician Nita Formation is sealed by thick, red bed and salt sequences at the base of the Carribuddy Group. These are excellent seals in the Permit area.

Source for hydrocarbons are provided by the thick, organic rich marine shales in the Ordovician Goldwyer Formation which are reportedly the richest source rocks in Western Australia and immediately underlie the potential Nita Formation reservoirs. Based on geochemical studies, they are interpreted to be thermally mature for oil generation I the targeted prospective part of the Permit.

Seismic reprocessing is planned to enhance seismic quality at the Nita Formation level and to bring out the character of the algal reservoir rocks to define algal build up structures for drilling.

The participants in EP 448 are Gulliver Productions (Empire Oil & Gas) with 25%; Maneroo Oil Company with 45%; Indigo Oil Pty with 20% and Kjirt Exploration Services with 10%.
Australia Eni developing Blacktip gas field
Rick Wilkinson OGJ Correspondent MELBOURNE, July 5 2006

Eni Australia Ltd. has begun development of Blacktip natural gas field in the southern Bonaparte Gulf of Western Australia. Plans include two initial development wells, a fixed production platform, and a 108-km subsea pipeline to an onshore treatment plant to be built at Wadeye on the Northern Territory shore. Blacktip, 330 km southwest of Darwin, was discovered in 2001. The onshore treatment plant will have a capacity to treat 1.3 billion cu m/year of gas.

Eni did not release a cost estimate, although an earlier plan to develop the field (with Woodside Petroleum Ltd. as operator) was estimated to cost $750 million (Aus.).
Eni bought Woodside's stake last year for $40 million and now has 100% interest in the field, which has a reserve estimate of about 1.2 tcf of gas plus 150 million bbl of condensate.
Eni has signed a 25-year agreement to sell the gas to Northern Territory's Power & Water Corp.

Meanwhile, Sydney-based Australian Pipeline Trust (APT) has signed a $400 million (Aus.) gas transportation deal with Power & Water Corp. to pipe the gas from Wadeye across the Northern Territory to intersect the existing Amadeus basin (central Australia)-to-Darwin pipeline at a point about 150 km south of Darwin.

ATP said the 227-km onshore pipeline will initially be capable of delivering 30 PJ/year of gas. Capital cost of construction is about $130 million (Aus.).

First gas from the Blacktip project is expected on stream at the beginning of 2009.
Australia Nexus Accepts Shell's Offer for AC/P23
Nexus Energy 6/6/2006

Nexus has accepted an offer from Shell Development Australia Pty Ltd to purchase 100% of Nexus' rights in relation to the gas (excluding the condensate) in the AC/P23 exploration permit (which contains the Crux gas-condensate field).

Shell's offer contains key commercial principles for the sale but is subject to the finalization and execution of definitive agreements as well as the receipt of necessary approvals.

The principal terms of the offer are:
Shell will pay for the rights in relation to the gas upon execution of agreements
Nexus will retain a 100% interest and operatorship of the gas-condensate recycle project and any other liquid hydrocarbons in AC/P23
Nexus is free to deal with its interest in the gas-condensate recycle project providing it does not affect Shell's rights in relation to the gas
Shell will have the right to take dry gas from AC/P23 at any time provided it doesn't adversely affect the gas-condensate recycle project
An exclusivity period will exist in relation to the Gas sale until the parties conclude definitive contract negotiations
The Independent Expert in Nexus' recent Target's Statement, issued on May 3, 2006, assessed the most likely value of Nexus' Browse Basin gas resources (including Crux and Echuca Shoals) to be A$41.9 million. The offer from Shell for the AC/P23 gas exceeds this value.

The deal will enable Nexus to undertake its gas-condensate recycle project as planned.
As indicated in previous Nexus announcements, Nexus is also reviewing proposals to farmout an interest in the planned gas-condensate recycling project. Under such a proposal, it is expected that the incoming farminee would fund 100% of the planned Crux appraisal well and feasibility engineering prior to expected project sanction in the first quarter of 2007.

"We are very pleased to have attracted an offer from one of the world's largest oil and gas companies. Nexus has been able to extract upfront value from a remote gas resource in less than 6 months – a fantastic achievement when viewed in relation to other major gas resources in the region, which have stood idle for more than 35 years. Nexus is also mindful that the deal represents good value for Shell as it adds to Shell's Browse Basin gas assets. We are pleased to be able to facilitate this truly win-win arrangement between our companies," said Ian Tchacos, Nexus' Managing Director.

"This offer provides Nexus with sufficient additional funding in the near term to progress its gas-condensate recycle project at Crux as well as the appraisal of the Echuca Shoals gas condensate resource. The rapid progress we are making in the Browse basin with Crux and Echuca shoals is very encouraging," said Ian Tchacos, Nexus' Managing Director.

Crux is a substantial gas and condensate resource in an emerging LNG province. Nexus acquired the asset for $12m in 2005 and has maintained a 100% interest in the Crux field and is appraising the asset with the intention of commencing its development phase by the second quarter of 2007. The field lies some 100 km to the north east of the 100% Nexus owned WA-377-P permit which contains the significant Echuca Shoals gas discovery which is adjacent to Inpex's Ichthys gas field, currently being considered for development as an LNG project.

In January 2006 Nexus commissioned a new 280 km² 3D seismic survey over the Crux field. This survey was completed in March 2006 and new structure maps for the Crux field have been generated using the new velocity data. Nexus believes these maps confirm additional resource potential in the north eastern part of the field. Nexus' best estimates of the Crux field contingent resources are 71 million barrels of condensate and 2 Tcf of gas.

Preparation for the drilling of the appraisal well, Crux #2, in Q4 of this year is underway. Nexus is actively seeking a rig slot and is purchasing the required drilling materials which will allow the well to be drilled when a slot does become available.

The next step in the forward plan for the project will be the completion of the front end engineering and design (FEED), which will incorporate the results from both the new 3D seismic data and the Crux #2 appraisal well.

The FEED will provide detailed design information on key components of the project. This information will be used by companies that will tender for the supply of the project's floating production storage and offload facility (FPSO) later in the year. In March 2006 Nexus appointed Mustang Engineering, an internationally respected engineering company, to execute the FEED and the work is progressing on schedule.
W. Australia EPA oppose Gorgon-Jansz LNG plant Gov override
Rick Wilkinson OGJ Correspondent MELBOURNE,  June 06, 2006

The Environmental Protection Authority of Western Australia has recommended for the second time against Chevron Corp. group's Gorgon-Jansz LNG Project on Barrow Island off Western Australian. The EPA first rejected the proposal in July 2003. This was overridden 2 months later by the Western Australian Cabinet, which said restricted access to the island could be set aside for the project subject to the Chevron group's demonstrating that environmental issues could be managed.

After studying a 3,000-page environmental impact statement subsequently tendered by Chevron, the EPA has reiterated its concerns on four main counts:
-- Potential interference with the rare, threatened Flatback turtle.
-- Potential impact to the marine ecosystem from dredging.
-- Potential for introduction of nonindigenous species on Barrow Island, a nature reserve.
-- The possibility of loss of subterranean and short-range endemic invertebrate fauna species.
On the first count, EPA Chairman Wally Cox said two of the most important nesting beaches of the Flatback turtle are adjacent to the proposed LNG plant site and the materials off-loading facility.  He said that because the life cycle, behavior, and feeding habits of the turtle were little known it is impossible to identify measures that would ensure survival of the species in this region.

Cox said Chevron and its joint venturers had not demonstrated that risks could be reduced to satisfactory levels on each of the other three points.  Chevron has said it is confident it can appeal the EPA's recommendations. It says it has operated safely at Barrow Island oil field for 40 years and suggests that without its presence the island's plant and animal life would have been degraded long ago.

The Western Australian government has the final decision on the project and can veto the EPA recommendations.
The two-train, 10 million-tonne/year LNG project, expected to cost in excess of $11 billion (Aus.), has earmarked customers in Japan, North America, and India. A final investment decision was to have been made early next year, subject to government approvals. On-stream date for LNG is nominally 2010, although there are now indications this could slip to 2011-12 (OGJ, May 15, 2006, Newsletter).
Tap Oil Makes New Oil Discovery with Amulet-1 Exploration Well 2006
Tap Oil 6/5/2006

Tap Oil says the Amulet-1 exploration well, located in Production License WA-8-L in the Dampier sub-basin, drilled to its revised total depth. Preliminary analysis of the log data indicates the presence of a 24-meter gross oil column. An oil water contact was confirmed by pressure data. The net oil column is approximately 20 meters with reservoir quality being considered reasonable at around 40-100 mD permeability and 20% porosity. Oil samples have been recovered to surface which suggest a light crude similar to that produced from the nearby Talisman field.

The evaluation program for Amulet-1 will continue over the next week. This program will include coring of the reservoir alongside the original vertical well, and then a sidetrack well approximately 500 meters away from the original vertical well, to evaluate the extent of the hydrocarbon bearing reservoir.

this was a sole risk well proposed by Tap oil original participants being Tap and Kufpec Australia Pty Ltd (Kufpec) at 50% equity each. Accordingly, Santos, which holds a 37.3685% interest in the permit elected not to participate in the drilling costs of this exploration well. On receiving the log data on the well, Santos has now elected to participate in the ongoing evaluation program pursuant to the WA-8-L Joint Operating Agreement. In summary, the JOA requires that if the discovery is developed and should Santos participate in that new field development then santos will relinquish its share of production to Tap and Kufpec until the proceeds from the sale of that production (less operating costs) equals a multiple of 15 times Santos' 27.3684% share of the well costs up to the election to participate in the forward program.

At this stage, the discovery of an oil field at Amulet-1 is encouraging however its commercial viability is yet to be established. The oil column intersected is below Tap's pre-drill expectations indicating that recoverable volumes are likely to be substantially less than pre-drill estimates. The forward evaluation program of coring and sidetracking will assist in estimating the recoverable volumes and hence provide an indication of the commerciality of the field. This information is expected to be available over the next few weeks.

Following Santos' election to participate in the forward program, the revised WA-8-L permit participants are Tap (Well Manager) with 20%; Santos (Permit Operator) with 37.3685%; and Kufpec with 42.6316%.
Great Artesian Suspends Cadenza-1 as a Gas Discovery 2006
Great Artesian 6/5/2006

Great Artesian says that the Cadenza-1 is being cased and suspended as a potential future gas producer. Further cased-hole production testing will be conducted in about three months when appropriate equipment and a smaller workover rig are sourced. DST-2 over the interval 2641-2644m was aborted on Saturday because of a mechanical packer failure. It was then decided to protect the hole with casing and defer further testing until a later date. Based on analysis of wireline logs and gas shows encountered while drilling a number of hydrocarbon bearing zones are interpreted in the well. DST-1 conducted on 2 June has previously confirmed deliverability from the zone 2691-2694m with a flow of 1.5 million cubic feet of gas per day (MMCFGD) through a ½ inch choke.

Ensign Rig #30 commenced drilling Cadenza-1 on May 18, 2006 and reached a total depth of 2993m in the Merrimelia Formation on May 30, 2006. Drilling and evaluation of Cadenza-1 was expected to take approximately 21 days. The rig is expected to be released late today or early tomorrow.

The Cadenza-1 well was fully funded by Energy Investments Limited a fully owned subsidiary Everdue Pty Ltd. In the event of a commercial discovery both Great Artesian and Energy Investments will each hold a 50% interest in any subsequent production license.

Cadenza-1 is located approximately 2.5 km north-northeast of the Paranta-1 new gas/condensate discovery. Cadenza-1 targeted an anticlinal feature which has the potential to host a total of between 12 (P50) and 28 (P10) BCF of gas within a number of levels of the Patchawarra Formation. The Patchawarra Formation is the primary reservoir target within the region and contains the main zones of interest within the Rossco-1, Udacha-1 and Middleton-1 wells. Additional, secondary, potential is anticipated within the underlying Tirrawarra Formation. The Cadenza Prospect was delineated following interpretation of the Paranta 3D Seismic Survey acquired in October 2005 and also funded by Everdue.

Cadenza-1 is now the sixth, successive exploration well that Great Artesian has participated in since August 2005 to be fully funded by farminees. All three wells that Great Artesian has participated in this year (Udacha-1, Middleton-1 and Cadenza-1) have resulted in new field gas discoveries.
Queensland southeastern Cooper basin
By OGJ editors HOUSTON, May 4 2006

Avery Resources Inc., Calgary, will earn 40% interest in 365,000-acre ATP 789P in the southeastern Cooper basin under an agreement with Sunshine Gas Ltd., Brisbane, which remains operator.

Avery Resources will fund a 150 line-km 2D seismic program and the drilling of one well. The acreage, on which three wells have been drilled previously, is between Kenmore and Bodalla South oil fields and the Bargie oil discovery.
Browse basin Royal Dutch Shell PLC
near giant Ichthys/Brewster offshore gas field
By OGJ editors HOUSTON, Oil & Gas Journal Online, January 24, 2006

The Australian government awarded Royal Dutch Shell PLC's Australian unit 100% interest in a 1,000 sq km block in the Browse basin near giant Ichthys/Brewster offshore gas field.  Shell Development (Australia) Pty. Ltd. committed to seismic studies in the first three years and will reprocess a large 3D seismic grid and conduct in-depth reservoir analysis. It will carry out field development planning and drill 12 wells.  The acreage holds large potential for a further 3-year program, Shell said.

WA-371-P, formerly part of the relinquished WA-285-P, is in 200-300 m of water in the Caswell subbasin 450 km west-northwest of Broome.

The Ichthys complex of fields has an estimated 10 tcf of gas and 500 million bbl of condensate in place (see map, OGJ, Oct. 17, 2005, p. 34).
Browse basin Nexus receives another permit 2006
Rick Wilkinson OGJ Correspondent MELBOURNE, Mar. 9 2006

Nexus Energy Ltd., Melbourne, has been awarded a 100% interest in Browse basin permit WA-377-P off Western Australia.

The permit, which contains the 1983 Echuca Shoals gas-condensate discovery, lies 120 km southwest of the company's Crux gas-condensate field on Ashmore Cartier permit AC/P23 in the Timor Sea. Nexus is studying plans to develop the liquids in Crux via a gas-stripping project and a floating production, storage, and offloading vessel (OGJ Online, Sept. 27, 2005).

The new permit lies in the corridor of major Browse basin gas discoveries being evaluated for new LNG projects, including the Woodside group's Torosa (formerly Scott Reef), Brecknock, and Calliance (formerly Brecknock South) fields and Inpex of Japan's Ichthys-Brewster fields.

It is adjacent to Shell Development Australia's new WA-371-P permit on which Shell has committed to a total of 12 wells during the first 3 permit years (OGJ Online, Jan. 24, 2006).

The Echuca Shoals-1 wildcat on WA-377-P encountered two gas reservoirs, said Nexus. Based on this one well, Nexus estimates that the field contains 1.3 tcf of gas and 62 million bbl of condensate.
Casino gas field on stream off Victoria 2006
Rick Wilkinson OGJ Correspondent MELBOURNE, Oil & Gas Journal Online, February 02, 2006

Production has begun from Casino gas field operated by Santos Ltd. in the offshore Otway basin of western Victoria, Australia (see map, OGJ, Oct. 24, 2005, p. 51).

Delivery of first gas from the field was made to TRUenergy's Iona onshore processing plant near Port Campbell via subsea pipeline. From there it will be sent to South Australia and Australia's eastern seaboard.

TRUenergy (formerly TXU) has an initial 12-year contract to take up to 420 petajoules of Casino gas as well as from future developments nearby, which include the same group's recently discovered Henry field (OGJ Online, Aug. 3, 2005).

Casino is the second Santos-operated gas field in Australia to come on stream in the last 9 months following the Mutineer-Exeter field off northwestern Australia (OGJ Online, Mar. 31, 2005).

Both developments produced first gas well ahead of schedule. In Casino's case, first gas comes just over 3 years after discovery.

Casino is on permit Vic/P44 about 30 km offshore in 70 m of water. The field has been developed via subsea wellheads and a subsea pipeline, which makes landfall via a directionally drilled section under the beach and cliffs to the plant well inland.

Participants are Santos 50%, Australia Worldwide Exploration Ltd. 25%, and Japan's Mitsui & Co. 25%.
Carnarvon basin northwest Australia 2006
Chevron wins block off northwest Australia
Oil & Gas Journal Online, February 13, 2006

Chevron Corp. subsidiary Chevron Australia Pty. Ltd. and partners have received exploration rights to Block W05-16 in the Carnarvon basin off northwest Australia.

The W05-16 permit covers 1,020 sq miles. The Carnarvon basin includes the North West Shelf and Greater Gorgon area. The new acreage is adjacent to the gas fields of the Gorgon project.

The 3-year work program for the permit area includes geotechnical studies, 1,500 miles of 2D seismic data reprocessing, a 695 sq mile 3D seismic survey, and the drilling of two exploration wells. Seismic work will begin this year. There is potential for another 3-year work program, Chevron said.

Chevron will operate the block and hold a 50% interest. Shell Development Australia and ExxonMobil Corp. each will hold a 25% interest.
Northern Territory Australia Condensate plant proposed in Australia
Rick Wilkinson OGJ Correspondent MELBOURNE, Feb. 13 2006

Darwin Clean Fuels (DCF), a new project-specific company based in Sydney, has proposed a $450 million (Aus.) condensate processing facility at the East Arm Wharf in Port Darwin, Northern Territory, Australia.  The plant would use condensate produced with natural gas in fields in the Timor Sea and North West Shelf to manufacture transport fuels including gasoline, diesel, jet fuel, and LPG.

DCF has filed a notice of intent for the project with the Northern Territory government. Extensive community consultation is under way. The project is subject to design, engineering, feasibility, and environmental studies.  If approval is given this year, construction could begin early in 2007 and take 2.5 years to complete. Several clean-fuel projects have been proposed for the East Arm development area.
Perth basin first commercial offshore production An Australian start-up
Alan Petzet Oil & Gas Journal, March 6, 2006

The first commercial offshore production in the Perth basin off Western Australia will begin shortly when one of the country’s smaller oil fields is activated.

If it were to hold at an initial 10,000 b/d for all of its first year on line, Cliff Head field will have recovered more than one fourth of the 14 million bbl of proved and probable reserves.

Cliff Head, when discovered at Roc Oil Co. Ltd.’s first well in Australia in late 2001, was not commercial at then-prevailing oil prices near $20/bbl, said John Doran, Roc Oil chief executive officer.

The field figures in an OGJ special report on Australia that starts on p. 20.

Cliff Head is in 59 ft of water 7 miles off Geraldton in the Indian Ocean. It will become Australia’s fourth offshore oil producing region after the Bass Strait, Northwest Shelf, and Timor Sea.

Cliff Head field, on the WA-31-L production license, has oil in a stacked series of Permian sands at about 4,100 ft subsea in a structure sealed by Early Triassic Kockatea shale. The joint venture didn’t make the final investment decision until March 2005.

Oil at one of the delineation wells was reported to be of 33° gravity.

After setting the unmanned platform jacket at the field location in late December 2005, the Ensco 67 jack up began drilling the five producing wells to have electric submersible pumps and two water injection wells.

Upon completion of drilling in the field in April 2006, the rig is to begin a multiwell exploration program on nearby prospects.

Cliff Head oil will be pumped through an 83⁄4-mile pipeline to onshore processing facilities at Arrowsmith, and the crude will be trucked 215 miles to BP Australia Ltd.’s Kwinana refinery south of Perth.

Interests in the Cliff Head venture, with a capital investment of $265 million (Aus.), are Roc Oil, Sydney, 37.5%; Australian Worldwide Exploration Ltd., Sydney, 27.5%; Wandoo Petroleum Pty. Ltd. of Japan, 24%; Voyager Energy Ltd., Perth, 6%; and CIECO Exploration & Production (Australia) Pty. Ltd., 5%.
Australia Cooper basin 11 MMcfd
By OGJ editors HOUSTON, Mar. 7 2006

Gas flowed at the rate of 11 MMcfd on a drillstem test of Permian Patchawarra at an exploratory well 50 km west of Moomba.  The flow rate at the Middleton-1 discovery well is one of the strongest recorded in the Cooper basin of South Australia, said Beach Petroleum Ltd., Adelaide, and Great Artesian Oil & Gas Ltd., Sydney. Each has 50% interest.

The gas flowed from 2,653-63 m on a 5/8-in. choke with 1,170 psi flowing pressure. Beach said the tested sands were interpreted to have 7 m of net gas pay and that the well has 3 to 9 m of likely gas pay in other sands. The discovery is 6 km northeast of Santos Ltd.-operated Raven gas field.

Victoria Petroleum potential 23 million barrels of oil 04 07 2006
Victoria Petroleum on Friday began drilling its Lightning-1 well in permit PEL 115 of Australia's Cooper Basin. Victoria, the operator with 40 percent interest in the well, said Monday morning that the operation was preparing to run 9 5/8 inch casing at 645 meters. Other participants include Impress Ventures (40 percent) and Roma Petroleum (20 percent).

Lightning-1 will test the Greater Mirage Murta oil pool concept of a potential 23 million barrels of oil in place over the Mirage-Lightning area. In addition, it will test the deeper Permian Patchawarra section with Mirage Oil Field in PEL115  the interpreted potential to contain a recoverable target of up to 130 billion cubic feet of gas or 18 million barrels of oil--if oil and gas are present.

Lightning-1's primary targets are the Murta sands at 1,307 meters and the stacked sands of the early Permian Patchawarra formation over the interval 1,927–1,967 meters. Its secondary targets are the sands of the McKinlay, Namur, basal Birkhead, and Hutton formations.

Victoria said that it expects to drill the well to a total depth of 2,007 meters in two weeks from the start of drilling. The joint-venture partners were encouraged by the recovery of approximately one barrel of oil cut mud oil from sands of the Patchawarra Formation in Plotosus-1, 3 kilometers to the northeast and down dip of Lightning-1. Their belief in Lightning-1's hydrocarbon potention was bolstered by the discovery of up dip gas shows in the previously drilled Burruna-1 in basement overlain by the sealing Murteree shale. The shale seals the Patchawarra Formation in the adjacent major Permian oil and gas fields 10 kilometers to the north of Lightning-1. Burruna-1 lies two kilometers to the southwest of the Lightning-1.

"Victoria Petroleum is pleased to have started drilling at Lightning-1 to prove that the shallow Murta formation in this well, if oil is present, may be part of the Greater Mirage Murta oil pool," remarked John Kopcheff, Victoria's managing director. "While we expect oil exploration success at the shallow Murta formation level, exploration success in the deeper Permian section, if oil, would prove up a new significant Permian oil resource in the southern part of the permit."

"If exploration success proves up Permian gas, this will be significant," added Kopcheff. "Lightning-1 is 400 meters from the open-access Moomba to Sydney gas pipe line, thus ensuring ready access to the Sydney gas market."
Australia coalbed methane
By OGJ editors HOUSTON, Mar. 9 2006

A group led by Eastern Star Gas Ltd., Sydney, spudded the first well in a vertical, 40-acre nine-spot coalbed methane pilot on PEL 238 in the Gunnedah basin, New South Wales.

The pilot is intended to accelerate dewatering of coals in the Bohena seam in the basal part of the Early Permian Maules Creek formation at 3,300 ft in the Bibblewindi-1 well, which was fracture stimulated and placed on continuous production test in late 2004.

The nine wells are expected to be on production by mid-2006. PEL 238 covers 9,100 sq km between Narrabri and Gunnedah.  Project interests are Eastern Star and Hillgrove Resources Ltd., Sydney independents, 32.5% each, and Gastar Exploration Ltd., Houston, 35%.

Australia's Reserves
Discoveries, pending developments spell resurgence in Australia offshore production
Paul Williamson Steven le Poidevin
This is the second part of a two-part article about how Australia is converting substantial hydrocarbon resources into recoverable volumes.

In the southeastern part of Australia, the Gippsland basin contains one gas field, Patricia/Baleen, that is now producing but was classified as economic demonstrated resources (EDR) in “Oil and Gas Resources of Australia 2002.”3

Patricia/Baleen gas field is 23 km off eastern Victoria in 50 m of water. The development consists of two subsea well completions connected via a 23-km offshore gas pipeline to an onshore dedicated gas treatment plant for processing and compression. The publicly estimated initial reserves are 77 bcf, while field life is estimated at 7 years.

Kipper oil and gas field has development plans under consideration. The field was discovered in 1986 by the Kipper-1 exploration well 45 km off Victoria in 100 m of water. The options under consideration assume a subsea development of the field (which extends between two titles) under unitization agreement with Esso/BHP Billiton.

A preliminary development plan for Basker/Manta oil field in the Gippsland basin has been submitted to state and federal governments. These fields are to be developed on a stand alone basis using a turret-moored floating production storage and offloading vessel (FPSO).

The Bass basin west of the Gippsland basin contains one gas and oil field, Yolla, that was classified as EDR in “Oil and Gas Resources of Australia 2002.”3 The Yolla development began construction in April 2003 and is expected to achieve full production by the end of 2005.

Yolla field is 120 km off Tasmania and 220 km southeast of Melbourne in 80 m of water. The field was discovered in 1985 by Amoco’s Yolla-1 well that intersected gas in the Intra-Eastern View Coal Measures (EVCM) reservoir units at 2,718-3,000 m. The reserves are publicly estimated at 236 bcf of sales gas, 1 million tonnes of LPG, and 14 million bbl of condensate.

The Yolla field development consists of a conventional steel platform, two deviated development wells, and a 147-km, 350-mm plain carbon steel subsea pipeline for the shipment of raw gas and condensate to an onshore treatment plant in Victoria.

The Otway basin farther to the west contains three gas fields that were classified as EDR in “Oil and Gas Resources of Australia 2002.”3 In January 2005, BHP Billiton started production from one of these, Minerva. The field is 10 km offshore in 60 m of water.

The Minerva development consists of two subsea wells and a flowline for transport of gas to the onshore gas processing plant, where gas liquids are removed prior to exporting the gas to market.

Two other offshore gas fields, Thylacine and Geographe, are under development. Nearby Casino gas field is in advanced planning. Another significant field, Henry, has recently been discovered adjacent to Casino. Due to the proximity of domestic markets, it is probable the remaining EDR field and any future large gas discoveries will be brought into production rapidly.

In the same area in April 2004 the Australian government granted production licenses to Woodside Energy Ltd., Perth, over Geographe and Thylacine gas fields (the Otway Gas Project). The fields are 55 and 70 km offshore in 80-100 m of water.

The project includes construction of an onshore gas processing plant, construction of the 11.5-km onshore pipeline from the shore crossing to the gas plant, the shore crossing, 70 km of offshore pipeline tied in to the Thylacine offshore platform, construction and installation of the offshore platform over Thylacine field, and drilling of four Thylacine production wells.

Initially the Otway Gas Project will produce 55 bcf/year of sales gas. The reserves for the combined Geographe and Thylacine fields are publicly estimated at 800 bcf of gas and 9 million bbl of condensate. Production is to begin in mid-2006.
New exploration incentives

The number of exploration wells drilled off Australia over the last decade has averaged 56/year with a maximum of 73 in 1998. In 2004, 44 offshore wildcat wells were drilled.

The industry in Australia, however, talks of the need to find a new Bass Strait (a new major oil province). This is because estimates of future production of oil and condensate suggest that at the mean expectation production rates would drop by around 50% by 2010 largely due to a drop in oil production.

The production of crude oil and condensate from 1975 to 2003 and production forecast of crude oil and condensate from 2004 to 2025. The forecast includes production of crude oil and condensate from accumulations that had been discovered by the end of June 2004 plus production of crude oil and condensate from undiscovered accumulations.

The 2004 forecast includes 10% of production from the Joint Petroleum Development Area (JPDA). Condensate production was projected to continue to grow, but the rate of growth was constrained by gas production rates and overall by the development timetable for the major gas fields. Consequently, the rate of discovery of new oil fields was insufficient to replace the oil reserves that are being produced.3 9

The Australian government announced its new initiative largely in response to the demonstrated decline in forecast production of oil in Australia over the next 10 years. The government acknowledges that 90% of all oil exploration success in Australia since the 1940s has been directly underpinned by geoscience information and advice given by Geoscience Australia and its predecessor organizations. Consequently, the government is providing via Geoscience Australia substantial support free of charge to help industry in the search for a new oil province.

The new $25 million (Aus.) program for enhanced data access was announced in May 2003 as described by Williamson and Foster7 and has been under way for 2 years. The program aims to further stimulate industry activity in Australia.

As part of this program the government has sought to increase the ready access to exploration data. The aim of the initiative is particularly to allow for new data to promote petroleum exploration in areas that could provide the possibility of a major new oil province. Funding is over 4 years to provide vital geological and seismic data to companies considering oil exploration in Australia.

Products from the program include commercial seismic and other data that have been collected over the Bremer, Mentelle, and Vlaming subbasins off southwestern Australia that are publicly available at the cost of transfer. The results of studies of these data will be presented in a workshop in Canberra in October 2005.

Consultation had been undertaken with the Australian and international petroleum exploration industry to identify areas that show the greatest potential for containing large undiscovered oil provinces.

Areas have been defined in the south, west, and east of Australia as possible targets for new data collection.

A new geochemical data set was collected as the seeps and signatures study on the North West Shelf and Arafura Sea. This study of natural hydrocarbon seepage and related geology in the Yampi shelf and Arafura Sea emphasized best practice methods through alliances with international groups proficient in the field. Synthetic aperture radar data was also used to investigate the presence of oil seepages.

The aim of these precompetitive surveys was to establish that a suitable geological history has occurred for large oil accumulations to have been formed and that oil is actually present in the area. The targeted areas over the next 3 years range from shelfal depths to deep water.

The likelihood of this program succeeding is helped by the very low level of total exploration around Australia. The relatively small number of wells drilled in such a large area as Australia leaves considerable opportunity for further exploration, discovery, and development.

The data collected by Geoscience Australia for this initiative will be the subject of ongoing regional studies that will be publicly available. Areas for studies by Geoscience Australia have been prioritized. Survey data will continue to be acquired over these areas over the next 2 years.

The results of precompetitive studies of these regions will be available for explorers to assess the prospectivity of acreage in the regions made available for bidding under the work program bidding system in Australia.7 10

Funding is also being provided to enable the copying of more than half a million tapes held by Geoscience Australia onto modern storage media. This preservation is necessary to ensure valuable seismic data are not lost because of the deterioration of old technology tapes.

The government allocated $25 million (Aus.) to allow remastering of seismic data in the repository and collection of new data to further stimulate exploration. Over 250,000 field tapes from previous exploration have already been remastered to high-density media and can be more conveniently loaned to industry. The tapes of field data and processed surveys are being remastered to 3590 cartridges. The greater data availability of data allowed by the remastering is now seeing more than twice the usual levels of data being loaned for assessment of petroleum exploration acreage released in April 2005.

For this part of the initiative, remastering of data began in November 2003 and will continue to mid-2007. The program is on schedule. The priority is to remaster data on older media most likely to be affected by stiction that threatens loss of data. Industry has greeted the decision as a vital step in enhancing the attraction of Australia as a place to invest in petroleum exploration.

This initiative builds on Australia’s already superior access to petroleum exploration data that began with the enactment of the “Petroleum Search Subsidy Act” in 1957, when petroleum exploration data at low to no cost became publicly available from Geoscience Australia after a brief confidentiality period.

Petroleum companies have since then used the data to assess the prospectivity of release acreage and help in decisions to take up acreage. Geoscience Australia and state and federal colleagues use the data described above and other data to promote the gazetted exploration release acreage that is announced at the Australian Petroleum Production and Exploration Conference early each year.

In addition new tax incentives were introduced in 2004 and continued in the 2005 release to further stimulate offshore frontier exploration. Nominated frontier areas offered in the acreage releases will attract 150% uplift for tax purposes. This is on top of a fiscal regime and political stability that already encourage petroleum exploration and development and have resulted in established oil and gas provinces.

1. Nelson, R., “Time to turn the key for exploration,” in “Prospect,” June to August 2005, Western Australian Government, 2005.
2. Geoscience Australia, “Oil and Gas Resources of Australia 2003,” Geoscience Australia, Canberra, 2005.
3. Geoscience Australia, “Oil and Gas Resources of Australia 2002,” Geoscience Australia, Canberra, 2004.
4. Quantum Harris, “Offshore Petroleum Information Review Report,” prepared for Department of Primary Industry and Energy, April 1995, 80 p.
5. Powell, T.G., “Australia’s hydrocarbon provinces-Where will the future production come from?,” APPEA Journal, Vol. 44, No. 1, 2004, pp. 729-740.
6. Longley, I.M., Bradshaw, M.T., and Hebberger, J., “Australian Petroleum Provinces of the 21st Century,” in Downey, M., Threet, J., and Morgan, W., eds., “Petroleum Provinces of the 21st Century,” AAPG Memoir 74, 2001.
7. Williamson, P.E., and Foster, C., “New Australian initiatives for greater access to exploration data,” OGJ, Apr. 26, 2004, pp. 37-46.
8. Western Australian Department of Industry and Resources, 2005 (
9. Powell, T.G., “Understanding Australia’s petroleum resources, future production trends and the role of frontiers,” APPEA Journal, Vol. 41, No. 1, 2001, pp. 273-285.
10. Williamson, P.E., and Foster, C., “Access to Australian exploration and production data: a critical factor in attracting investment,” APEA Journal, Vol. 43, No. 1, 2003, pp. 693-704.
The authors
Paul Williamson ( is group leader of the innovation and specialist services group with Geoscience Australia. His interests have been in petroleum prospectivity analysis, the structure of continental margins, petroleum technical advice, identified petroleum resources, and petroleum data management and access. Current responsibilities are for specialist geoscientific and database services for assessing and promoting prospectivity.
Steven le Poidevin ( is a senior petroleum engineer in the petroleum and greenhouse gas advice group of Geoscience Australia. His interests are in assessing Australian oil and gas reserves and identified resources and providing engineering technical advice to regulators of Australian offshore petroleum exploration and production.

OGJ, Oct. 24, 2005, p. 51 

Australia's Reserves
Discoveries, pending developments spell resurgence in Australia offshore production
Paul Williamson Steven le Poidevin
This is the second part of a two-part article about how Australia is converting substantial hydrocarbon resources into recoverable volumes.

In the southeastern part of Australia, the Gippsland basin contains one gas field, Patricia/Baleen, that is now producing but was classified as economic demonstrated resources (EDR) in “Oil and Gas Resources of Australia 2002.”3

Patricia/Baleen gas field is 23 km off eastern Victoria in 50 m of water (Fig. 5). The development consists of two subsea well completions connected via a 23-km offshore gas pipeline to an onshore dedicated gas treatment plant for processing and compression. The publicly estimated initial reserves are 77 bcf, while field life is estimated at 7 years.

Kipper oil and gas field has development plans under consideration. The field was discovered in 1986 by the Kipper-1 exploration well 45 km off Victoria in 100 m of water. The options under consideration assume a subsea development of the field (which extends between two titles) under unitization agreement with Esso/BHP Billiton.

A preliminary development plan for Basker/Manta oil field in the Gippsland basin has been submitted to state and federal governments. These fields are to be developed on a stand alone basis using a turret-moored floating production storage and offloading vessel (FPSO).

The Bass basin west of the Gippsland basin contains one gas and oil field, Yolla, that was classified as EDR in “Oil and Gas Resources of Australia 2002.”3 The Yolla development began construction in April 2003 and is expected to achieve full production by the end of 2005.

Yolla field is 120 km off Tasmania and 220 km southeast of Melbourne in 80 m of water. The field was discovered in 1985 by Amoco’s Yolla-1 well that intersected gas in the Intra-Eastern View Coal Measures (EVCM) reservoir units at 2,718-3,000 m. The reserves are publicly estimated at 236 bcf of sales gas, 1 million tonnes of LPG, and 14 million bbl of condensate.

The Yolla field development consists of a conventional steel platform, two deviated development wells, and a 147-km, 350-mm plain carbon steel subsea pipeline for the shipment of raw gas and condensate to an onshore treatment plant in Victoria.
Australia ’s natural gas reserves 90 trillion cubic feet (Tcf), the largest reserve in the Asia Pacific region (2004E).

The most abundant reserves are located offshore of the northwestern coast in the Carnavoran Basin (40 Tcf of proven natural gas), an area more well-known as the Northwest Shelf. Other important basins, including the Cooper/Eromanga basin in Central Australia and the Bass/Gippsland basin offshore of southern Australian, account for approximately 10 Tcf of reserves.

Natural gas presently plays a relatively small role in Australia ’s fuel mix (approximately 17%), but consumption has grown steadily, from 710 Bcf in 1995 to 893 Bcf in 2002. Australia ’s natural gas consumption is projected to grow twice as fast as the consumption of other energy sources in the next two decades, and it is expected to account for 24% of total energy consumption by 2020.

Natural gas production in Australia has increased rapidly since 1995, from 690 Bcf to 1.26 Tcf in 2002. Despite declining production capacity in the Cooper/Eromonga Basin, production is expected to grow 3.5% in 2004. An explosion at Santos ’ Moomba gas-processing plant in January 2004 has further affected natural gas production.

The status of abundant reserves in the Timor Sea has been partially resolved. In May 2002, East Timor expanded its maritime territory claim and challenged Australia ’s claim to 25 Tcf of reserves in the Browse/Bonaparte Basin. In March 2003, the Timor Gap Agreement was established, creating a Joint Development Area (JDA) between the countries and setting the division of royalties from hydrocarbon production at 90:10 in favor of East Timor . Only the Bayu Undan natural gas field (3.4 Tcf), which began operation in February 2004, lies wholly within the JDA. Eighty percent of the Greater Sunrise field (9.3 Tcf) is located outside of the JDA. The Timor Sea also contains natural gas in the Evans Shoal, Petrel, and Tern gas fields, estimated to contain 4 Tcf of natural gas combined. ConocoPhillips, Woodside, and Shell are the main operators in the Timor Sea .

Recent natural gas exploration in Australia has resulted in several important discoveries including ExxonMobil’s June 2002 discovery of 20 Tcf of natural gas in the Jansz field of the Northwest Shelf. In 2001, natural gas discoveries were made in Southern Australia 's Otway Basin , raising estimates of that basin’s reserves to 1.6 Tcf. Furthermore, Apache Corporation recently announced that 800 Bcf of reserves had been identified at its John Brookes site. In September 2004, Woodside Petroleum announced a find in the Polkadot-1 exploration well off the northern coast. It is expected to begin production in 2005. Additional natural gas discoveries will likely be made inadvertently as a byproduct of Australia ’s recent surge in petroleum exploration, as past exploration in the deep waters off Southern Australia has primarily resulted in the discovery of natural gas.
Coal Bed Methane Map

Australia ’s existing pipeline infrastructure is fragmented and was built to carry gas from centrally located fields to coastal urban hubs including Sydney and Melbourne. With centrally located fields in decline, however, and offshore projects on the rise, a large investment in the country’s pipeline network will be necessary to bring additional natural gas into the grid. Australia estimates that it will require US$5.5 billion of new investment over ten years to efficiently use natural gas to generate power.

In May 2004, Woodside and Origin Energy announced their commitment to the development of offshore Otway Basin gas reserves. Construction of the Thylacine gas field will begin this month, while development of the Geographe field will be connected at a later date. Recent announcements of two other projects rely on discoveries from the 1970s. Woodside indicated that Browse, another proposed Australian LNG station, will begin exports by 2011. BHP is considering a floating LNG facility to process the estimated 8 Tcf in its Scarborough reserves, and it announced in September 2004 that Onslow was the preferred site for another facility.

The Australian Pipeline Trust (APT) operates over 4,350 miles of pipelines (oil and gas combined), while Epic Energy operates around 2,485 miles of pipelines (oil and gas combined).

Although Australian Gas Light (AGL) is the leading owner of gas pipelines, they are operated by APT.

Ongoing tensions between pipeline companies and regulators may discourage the entry of new investors. For example, Australian Epic Energy put its pipeline assets up for sale in September 2003 after determining that regulated pipeline tariffs were too low for profitable operation. Other companies, including the Australian Pipeline Trust, have halted construction on proposed pipelines due to regulatory environmental concerns. In August 2004, the Australian Pipeline Trust began negotiations with US-based CMS to sell US$158 million of gas pipelines in Western Australia . Many Australian and international investors, as well as the Australian Pipeline Industry Association (APIA), are calling for regulatory reforms to improve the situation.

Australia $420b worth of projects in pipeline
February 7, 2006 - 8:09AM

Australian mining and transport companies and governments have $420 billion worth of projects in the pipeline, a new survey shows.
The Delta Electricity/Access Economics investment monitor report released Tuesday showed the total value of projects planned or under way at the end of December 2005 was $420 billion, up $21 billion or 5.4 per cent on the September quarter.
The figure was up 27.5 per cent on a year ago.
The value of mining and metals projects under construction was up 131 per cent on a year ago, with high energy prices putting a focus on liquid natural gas.
The report showed significant investment in iron ore, coal, gold, nickel, alumina and aluminium.

The value of projects under construction and committed to, known as definite projects, fell $7.9 billion to $121.9 billion over the September quarter, reflecting completion of some significant projects such as Sydney's M7 Motorway and the Port of Dampier upgrade.  But the figure was up $7.1 billion from 12 months ago.
Liquefied Natural Gas (LNG)
Liquefied natural gas (LNG) exports have greatly increased Australia ’s natural gas production since it began exporting the commodity in 1989. In 2002, Australia was the world’s sixth largest LNG exporter, accounting for 7% of global LNG exports. Japan is the primary destination of Australia ’s LNG supplies, with smaller shipments to South Korea and Spain . Australia secured contracts to supply LNG to China in 2002 and South Korea in 2003. Initial negotiations began with Mexico in September 2004 in an effort to tap the LNG market on the US West Coast.

Australia ’s natural gas reserves are found in three areas: the Bass Strait , the Cooper/Eromanga Basin, and on its west and northwest coasts. The Northwest Shelf Venture (NSV), a consortium of six energy companies led by Woodside Petroleum, operates three offshore LNG trains. It relies on natural gas supplies from North Rankin (19.3 Tcf) and nearby fields of the Northwest Shelf (NWS). NWS produces 8% of world LNG supplies, mostly for export to Japan . Construction on a fourth train was completed in July 2004. A fifth train has been proposed, but has only received support from Woodside and BHP Billiton. Further support for another train may be influenced by NSV’s winning a bid to supply China ’s Guandong LNG terminal beginning in 2005. The development of pipelines across the western half of the country may allow NWS to supply domestically to Australia ’s southeastern states in the future as well.

Although NSV dominates Australia ’s LNG market, other LNG projects are being developed as well. NSV members ChevronTexaco (57% ownership), Shell (29%) and ExxonMobil (14%) are developing a proposal for the Northwest Shelf's 12.9-Tcf Gorgon field. The project entails the construction of a pipeline to transport natural gas from the Gorgon field to Australia ’s Barrow Island , where a liquefaction plant with an annual capacity of 238 Bcf per year is to be constructed. ChevronTexaco has secured an agreement with an affiliate for the delivery of 95 Bcf per year from the Gorgon Venture to North America over a 20-year period beginning in 2008. In April 2004, Australia began talks with China ’s largest oil firm, CNOOC, to purchase a 12.5% share of Gorgon’s proven reserves. An estimated US$21 billion in sales over 25 years would make such a deal the largest export commitment in Australian history.

ConocoPhillips has proceeded with plans to construct a liquefaction plant on Australia ’s northern coast (at Darwin ) to be supplied by natural gas from the developing Bayu/Undan field (3.4 Tcf) by 2005. ConocoPhillips has a majority interest (64.4%) in the project, which it is developing with Santos (11.83%), Italy 's ENI (12%), and Japan 's Inpex (11.71%). In March 2002, ConocoPhillips arranged to sell 3.6 million tons (convert) of LNG per year from the Darwin plant to Tokyo Electric Power Company and Tokyo Gas Company for 17 years beginning in 2006.

Another LNG project, led by Woodside Petroleum (33%) in a consortium with ConocoPhillips (30%), Royal Dutch/Shell (27%) and Osaka (10%), has been proposed for the Greater Sunrise natural gas field (9 Tcf) in the Timor Sea . The consortium has announced its plans to develop the project by constructing a floating LNG plant with a proposed capacity of 238 Bcf per year. Production is scheduled to begin in 2008.

Australia is also a significant exporter of LPG. Because the majority of reserves are located in the Northwest Shelf, however, the country is a net importer of LPG in its southeastern region. LPG consumption has fallen in the last several years, as energy efficiency measures have taken hold; production, however, continues to rise.

Duke Energy completed sub sea gas pipelines to link the mainland with Tasmania in both 2002 and 2003. Proposals for more pipelines have been delayed, as both Duke Energy and Epic Energy are in the process of selling pipeline assets. In March 2004, Duke announced the sale of three Australian gas pipelines and three gas-fired power stations to Alinta.

Current proposed natural gas pipeline projects reflect Australia ’s changing supply base, including offshore projects to support the LNG ventures described above. The 423-mile Sea Gas pipeline, which brings natural gas from the Otway Basin to Southern Australia ’s Quarintine power station in Adelaide , was recently completed.

A 1,300-mile proposed pipeline from Papua New Guinea (PNG) to Australia will deliver gas from the Kutubu/Moran natural gas fields in PNG Queensland. Progress on the pipeline has been paralyzed by a lack of commitment from its potential buyers. In February 2004, Oil Search Ltd, the main developer of the pipeline, committed to beginning its design without the requisite funding, noting that gas could flow by 2008 with investment of US$70 million from minority partners.
Australia $420b worth of projects in pipeline
In January 2004, the Australian government also commissioned a feasibility study on a possible 1,800 mile transcontinental pipeline to ship gas from the Carnarvon and Browse Basins to southeastern domestic markets.   The report said the fall in definite projects over the quarter was not of significant concern yet, but all eyes would be on the mining sector in the coming year.
"The pull back in the value of definite projects is not a major concern as yet, with ABS data showing that for those projects which are under way, there is still a high level of investment spending yet to be done," the report said.
"The value of projects in planning is very healthy.
"What may be more concerning is that resources is becoming the key driver of investment and resources is the most volatile component of investment."

The value of projects in planning was $154.9 billion "under consideration" and $143.2 billion which are "possible", the study said.


Papua New Guinea to Queensland, Australia 3,600 km l gas pipeline
The proposed $5 -billion (Aus.) Highlands natural gas pipeline extending 3,600 km from Papua New Guinea to Queensland, Australia, moved forward last year with the announcement (OGJ Dec. 13, 2004, p. 58) that Sydney based Australian Gas Light Co. (AGL) secured a long-term agreement to purchase 1.5 Tcf of gas over 20 years, starting in 2009.

The Australian component of the pipeline, using 20 compressor stations, encompasses three routes: Torres Strait to Gladstone, along the east coast, Townsville to Ballera across outback Queensland, and Weipa to Gove, across the Gulf of Carpentaria.
A branch off the east coast leg to Mount Isa is also being considered.

Project partners have total commitments for 220 Bcf/year, above the threshold demand of 200 Bcf/year in order to proceed with their plans. AGL also reached an agreement with project participant Oil Search Ltd. to take a 10% equity interest in the project for $ 300 million.

AGL already is in a partnership with Malaysian oil firm Petroliam Nasional Bhd as preferred developer in the $25-mllion program to design and construct the pipeline, which will deliver gas from the Kutubu and Hides fields in the central Papua New Guinea highlands.

AGL will purchase its gas for $4.5 billion to supply its eastern Australian network, which includes more than 3 million customers. The project moved to the front-end engineering and development stage in late 2004, and the partners expect to make a final investment decision during second-half 2006.
CBM exploration and production were of little significance in Australia until the late 1990s but are becoming an integral part of the Australian gas industry. The successful development of CBM fields has contributed to the diversification of gas supply sources, particularly in Queensland. CBM is poised to continue as an important energy source in Australia.
CBM and coalmine methane

CBM is the naturally occurring, methane-rich gas in coal seams and commonly known in Australia as coal seam gas or coal seam methane.

The CBM that is associated with coal mining is traditionally called coalmine methane. A total of 300,000 m of directional in-seam drilling is carried out every year for degasification purposes to enhance minesite safety at underground and highwall open-cut collieries in the Bowen basin in Queensland and the Sydney basin in New South Wales. In comparison, about 184,000 m were drilled for stand-alone CBM exploration or production in 2004 in Australia.

About 51 PJ of coalmine methane were emitted to the atmosphere in Australia in 2004. This is 111% of the commercial production of CBM in Australia or about 5% of Australia’s total primary domestic gas consumption in the same year. Drained coalmine methane is used at several collieries as either pipeline gas or fuel for on site electric power generation.

The coalmine methane that is emitted through mine ventilation systems is called ventilation air methane, which is the largest source (about 58% in Australia) of coalmine methane emissions. Ventilation air methane is also an untapped potential energy resource.

The potential use of mine ventilation air is largely restricted to on site power generation, because its methane content is very low (generally less than 1%). Specialized combustion reactors that can burn ventilation air methane are being installed at the Westcliff colliery in the Sydney basin.

Coalmine methane drainage and CBM resources are separately administered in both Queensland and New South Wales: the former by mineral resources legislation and the latter by petroleum resources legislation. In Victoria, however, CBM resources are administered under the legislation for mineral resources development.

As CBM is contained within the coal, conflicts between a developer of coal and coalmine methane and a developer of CBM can occur in an area where the CBM resource is located within a potentially economically minable coal deposit.

CBM accumulations are not necessarily related to the presence of anticlines. However, many CBM project areas are located on anticlinal trends, although not all of these anticlines may form valid structural closures. In addition, CBM project areas are often located near conventional gas fields.

Perth basin in Western Australia
Gas flow starts from Xyris gas field
ARC Energy Ltd., Perth, has brought on stream Xyris gas field in the northern Perth basin in Western Australia. Xyris is flowing 9.3 MMcfd of gas.

The gas flows through the Parmelia pipeline to Perth and southwestern Western Australia.

Xyris field, discovered in April 2004, is the first greenfield gas development in the Perth basin since the nearby Beharra Springs field began production in 1990.

ARC has a 50% interest in Xyris, with Origin Energy Developments Pty. Ltd., Sydney, holding the other 50%.

A new gas scheme was introduced in Queensland in January 2005. Designed to encourage the development of new gas supply sources such as CBM, the scheme requires electricity retailers to source at least 13% of their electricity from gas-fired generation or renewable resources. The 13% gas scheme has already acted as a catalyst for active exploration and development programs for CBM in Queensland.
Exploration and production

CBM exploration is based on hydrocarbon play concepts. However, traditional petroleum exploration theories and drilling practices are not necessarily applicable to CBM exploration and drilling. Permeability and gas content are the most important properties for CBM exploration and development.

Anticlinal trends are attractive targets for CBM exploration because the depth to a coal seam is often less on an anticline than on its flanks and also because fracture development is often more intensive along the anticlinal axis.

The capital cost of drilling a CBM well has decreased greatly in the last decade, with fit-for-purpose drilling technologies tried and developed on site in Australia. Some new production wells comprise pairs of a horizontal drainage well and a directly connecting vertical production well or trios of two horizontal wells and a vertical well.

 CBM drilling activity has been increasing substantially in terms of both the number of wells and metres drilled. A total of 277 CBM exploration or development wells were drilled in 2004 (Fig. 3). In comparison, 201 conventional petroleum exploration or development wells were drilled onshore or offshore in Australia in the same period.

The Permian Bowen basin remains the most actively explored and developed basin in Australia for CBM. The basin’s share of CBM drilling activity exceeded 80% of Australia’s total in 2004 in terms of number of wells and metres drilled. Wells are typically about 700 m deep in this basin.

A recent trend in CBM exploration is for resources at shallow depths in low-rank (low thermal maturity) coal seams of Jurassic age in the Surat basin in Queensland and in the Clarence-Moreton basin in Queensland and New South Wales. Wells are typically about 500 m deep in the Surat basin.

Lignite (brown coal) of Tertiary age has also become a target for CBM exploration. This new trend is based on the observation that, in spite of a smaller amount of CBM initially in place per unit volume of coal, low-rank coal at shallow depths (100 to 500 m) is more permeable than high-rank coal of Permian age at intermediate depths. Thus, CBM could be more easily desorbed from low-rank coal than from high-rank coal, resulting in a higher recovery factor.

 The commercial production of CBM (including coalmine methane use) has increased substantially since 1996, when coalmine methane use began in the Moura colliery in Queensland. Production is estimated to have reached 46 PJ/year in 2004 in Australia (Fig. 4).

Cumulative CBM production is about 179 PJ from 1996 to 2004. CBM production in Queensland was about 36 PJ/year in 2004, satisfying about 31% of Queensland’s total primary gas demand. CBM production in New South Wales was about 10 PJ/year in 2004, and much of this came from coalmine methane use at the Appin and Westcliff collieries.
Gas content

Subsurface coal contains a significant amount of CBM.