Onshore future on hold in Victoria

VICTORIA is home to four sedimentary basins that contain potential and known oil and gas plays: the Murray Basin, which remains largely unexplored; the Bass Basin, which is in Tasmanian waters; and the producing Otway and Gippsland basins.
According to the Victorian Department of Primary Industries (DPI), gas production from offshore Victoria is worth about $1.5 billion annually, with crude oil production valued at more than $2 billion.
More than 80 per cent of the gas reserves on the Eastern Seaboard can be found in the Bass Strait between Victoria and Tasmania; the majority in the Gippsland Basin.
In 1967 Australia’s largest oil field, Kingfish, was discovered by 50:50 joint venture partners ExxonMobil and BHP Billiton Petroleum (Bass Strait); in 1969 the partners produced the basin’s first gas, from the Barracouta field, which was sent to the Longford gas plant for processing.
Almost 45 years later, the 46,000 square kilometre Gippsland Basin remains Victoria’s most productive basin.
However, the DPI estimates that anywhere between 2 trillion cubic feet and 5tcf of gas may still remain undiscovered, as well as about 600 million barrels of oil.
In 2010 to 2011 the DPI recorded total oil and condensate production from Gippsland at 21.6mmbl; gas production at 0.27tcf and LPG production at 9.4mmbl. By far the largest contributor to 2010 to 2011 production was ExxonMobil, producing more than 21mmbl of oil and condensate and 256,823 million standard cubic feet of gas.
ExxonMobil and BHP hold a large number of petroleum tenements in the Bass Strait under the Gippsland Basin joint venture, and are currently expanding operations through the Kipper Tuna Turrum project, which has the potential to be one of the largest domestic gas developments on the East Coast.
The $4 billion expansion project began in 2010, and involves the development of two new fields: the Kipper field, which holds about 620 billion cubic feet of recoverable gas and 30mmbl of gas liquids; and the Turrum field, which holds about 1tcf of gas and 110mmblof
gas liquids.
As part of the project, new platform Marlin B was constructed above the Turrum field and linked by a bridge to the existing Marlin A platform; aimed at processing additional oil and gas which will be piped back to the Longford plant.
In the December quarter of 2012, Esso and BHP carried out hook-up activities to connect the new Marlin B platform to the existing Marlin A platform.
Initial production from Turrum will consist of low carbon dioxide gas, with further high carbon dioxide gas production scheduled for 2016 when essential upgrades to the Longford plant have been completed.
Another current Gippsland producer is Nexus, the owner-operator of the Longtom gas project, which reached first gas in October 2009; in the 2010 to 2011 period it produced 136,380bbl of oil and condensate and 13,022mmscf of gas.
In the same period, Roc Oil – operator of the Basker-Manta-Gummy fields – produced 21,333bbl of oil and condensate and 1120mmscf of gas. In 2012, Roc Oil suspended production as it moved into a non-production phase.
Otway Basin
Victoria’s other producing basin, Otway, extends from the Mornington Peninsula in Victoria to Cape Jaffa in South Australia, and has been producing gas and condensate since 1986.
Gas production began onshore at the North Paaratte field in the Port Campbell area; it remains one of the basins’ main producing fields alongside the Wallaby Creek and Iona fields. According to a 2002 DPI report on Otway gas, “initial recoverable gas reserves of the Victorian portion of the Otway Basin (Port Campbell region) were estimated to be about 59 billion cubic feet”.
“The remaining reserves, including new discoveries as at 30 June 2001, are estimated to be 36.7bcf and 893bcf for onshore and offshore respectively,” the report stated.
Between 2010 and 2011, the onshore Otway basin produced 1537bbl of condensate and 8189mmscf of gas, while the offshore basin produced 88,421bbl of condensate and 60,584mmscf of gas.
The basin is home to a number of operating fields, such as Santos’ Henry, Netherby and Casino fields; BHP Billiton’s Minerva field; and Origin Energy’s Geographe and Thylacine fields, which the company has developed through its $1.1 billion Otway gas project.
According to Origin, the Otway gas project is designed for average production of 60 petajoules of natural gas per year, together with about 100,000t of LPG and 800,000bbl of condensate per year.
Origin also produces gas and condensate from the Yolla field, which lies in Tasmanian waters, and transports it back to Victoria via subsea and onshore pipelines to the Lang Lang gas processing plant.
The BassGas operation began in 2006, and is designed to produce about 20PJ of sales gas per year, 1mmbl of condensate and 65,000t of LPG for the Victorian market.
Origin recently applied to carry out seismic testing near its Halladale discovery in the Otway Basin.
Future of Victorian oil and gas According to the Federal Government’s 2012 Australian Gas Resource Assessment, Australian gas consumption has grown by 4 per cent per year in the past decade, with gas accounting for 23 per cent of Australia’s primary energy consumption in 2009 and 2010, and 15 per cent of electricity generation.
The assessment also stated that gas consumption in Australia was expected to increase by 2.9 per cent per year to 2.4tcf in 2034 and 2035.
It stated that at the beginning of 2011, Australia’s total identified conventional gas resources were estimated at 167tcf, including 10tcf of inferred resources in recently discovered fields.
However, with the rate of reserves additions slowing down, the report suggested further opportunities for large discoveries remained with “the development of new technologies and play concepts, and the advance of exploration into frontier areas”.
According to the report, with total identified CSG resources of 203tcf and total identified tight gas resources at 20tcf, plus the potential for shale gas, Australia’s combined indentified gas resources had the possibility to reach 392tcf: equal to about 184 years of gas at current production rates.
With rising gas demand and depletion of conventional gas resources, the paper stated that unconventional sources of gas – CSG, tight and shale gas – would become more dominant in the next few decades.
“The distribution of gas resources in 2035 is expected to shift as finds of conventional gas resources offshore level off, CSG exploration and production continues to increase and new tight and shale gas resources are indentified and developed,” the report stated. Growth in gas demand and depletion of conventional gas resources would be reflected in Victoria, according to DPI energy development and engagement manager Geoff Collins.
In a report for the Victorian Supplement in 2012, Mr Collins said Victoria’s gas demand was continuing to grow and expected to double by 2030.
“Coupled with this demand scenario, we know the following about the supply side: Victoria’s current gas reserves – and discovery rate – indicate local gas will be substantially ‘depleted’ by 2030,” he said.
Mr Collins said the rise in gas demand would be driven by an increase in gas-fired electricity generation, and that development of new gas-fired facilities, such as the Mortlake and Tarrone stations, had already begun.
The 550MW Mortlake station in southwestern Victoria is the largest gas-fired power station in the state, and is connected to the Otway gas plant at Port Campbell by an 83km natural gas pipeline.
The station, operated by Origin Energy, was completed in August 2012. Natural gas and electricity company AGL Energy has announced plans to develop the $600 million Tarrone power project to supply the state in times of peak demand, involving the construction of an initial 500 to 600MW gas turbine power station near Willatook.
DPI earth resources development executive director Chris Brooks said that Victorian gas production was rising but at the same time, reserves were declining. Mr Brooks said the state’s gas fields had sufficient reserves to continue at current rates for about 15 more years, depending on demand, and that oil production had already declined significantly since its peak in the mid 1980s.
He said the Kipper Tuna Turrum oil and gas project and Otway Gas project would deliver new production, but further exploration was needed in new areas to promote growth.
“Victoria is expected to have sufficient gas supplies to meet demand into the near future,” he said.
“There is still a need to explore for more gas for the mid to long-term future and Victoria is examining all its options for new sources of supply.
“Existing reserves are limited to only a couple of play types in the offshore Gippsland Basin and one in the offshore Otway Basin.
“Other play types exist but to date have not been substantially investigated as they are higher risk than the current low risk plays.”
However, with the Victorian Government’s current hold on all approvals to undertake hydraulic fracturing (fracking) as part of onshore gas exploration – including a ban on the use of BTEX chemicals in the fracking process – further CSG exploration is unlikely to go ahead for some time yet.
In August 2012, the State Government stated it would not issue new exploration licences for CSG until the Federal Government’s National Harmonised Framework for CSG had been considered.
The national framework would examine leading practice approaches to the regulation of the CSG industry, including water management and monitoring, well design and integrity, fracking, chemical use and industry and community engagement.
Mr Brooks said the hold on CSG exploration would continue until the national framework was finalised.
“Victoria already has a strong framework for regulating onshore gas operations,” he said.
“The national framework is designed to enhance this by delivering greater levels of consistency, certainty and transparency in the development of the coal seam gas industry across Australia.
“A draft framework has been released and the Victorian Government has strongly encouraged interested parties to make submissions.”

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