Bass Strait’s $300b bonanza fuels more hope
IN the 40 years since the discovery of oil in Bass Strait, the Gippsland Basin operation has deposited $300 billion (in today’s money values) in federal government coffers, according to independent modelling — and there is a lot more to come.
Mark Nolan, chairman of ExxonMobil Australia, says it is confident that there are 20 more years of production ahead. The country’s largest oilfield, Kingfish, continues to be an important contributor and has already delivered more than a billion barrels.
The Kingfish, Halibut (oil) and Barracouta (gas) discoveries by what was then Esso Exploration Australia and its joint venturer, now BHP Billiton, generated huge excitement in the late 1960s, transforming Australia’s oil supply situation from almost complete dependence on imports to substantial self-sufficiency. At the time, crude oil was our most costly import.
The Bass Strait fields, with subsequent discoveries, have yielded more than 3.5 billion barrels of oil (556 billion litres) and almost six trillion cubic feet of natural gas — nearly 63 per cent of Australia’s oil production and almost 30 per cent of cumulative gas production. The fields are among the most profitable in the world for the two resource giants.
Modelling of the economic value undertaken by Econtech for ExxonMobil estimates that the Gippsland operations have added about $2.2 billion annually to Australia’s GDP (in inflation-adjusted terms) and stimulated more than 50,000 jobs in Victoria.
The development has demanded massive investment, and not only by ExxonMobil and BHP Billiton. Econtech calculates that the average annual capital outlay by other businesses stimulated by the Bass Strait projects over four decades has been $700 million (inflation-adjusted), or 1.5 per cent of Australian capex spending.
There are now 18 offshore platforms and three subsea facilities in Bass Strait carrying oil and gas to shore at Longford, near Sale, through 1000 km of onshore and offshore pipelines. Consequently, at Barry Beach there is a construction site for offshore platforms and a marine supply terminal for a fleet of drilling vessels and supply boats.
Total cumulative investment in infrastruc- ture to develop, produce and process crude oil and gas stands at more than $12.5 billion.
Extending the life of the petroleum province also requires ongoing large expenditure. ExxonMobil says the joint venture has outlaid $100 million on seismic investigation this decade and $300 million since 2002 on drilling wells around the Kingfish, Bream, Halibut and Fortescue platforms.
The rewards have been an additional trillion cubic feet of natural gas reserves and a capacity to sustain oil liquids production at 127,000 barrels a day, well short of the fields’ 500,000 barrels a day output at their peak, but still a healthy contribution to corporate and tax income.
Just the 30,000 barrels a day of liquids added by recent drilling exploration is worth about $1 billion a year on present oil prices — and a substantial further contribution to federal government revenue.
ExxonMobil, BHP Billiton and Santos are now engaged in a joint venture to develop the Kipper field, an almost $1 billion project which is the largest undertaken since the discovery of the initial trio of fields. When Kipper comes into operation in 2010 it is expected to deliver the partners 620 billion cubic feet of natural gas and 29 million barrels of condensate and liquid petroleum gas over its lifetime.
ExxonMobil and BHPB are already at work on the next project beyond Kipper — the development of the Turrum field, estimated to hold 800 billion cubic feet of gas, from a new platform linked to its existing Marlin structure. First gas production is planned for 2011.
‘‘ There are substantial gas resources remaining in the Gippsland Basin,’’ says Mark Nolan, noting that the joint venture has added enough gas to its reserves in the past three years to power a city the size of Adelaide for two decades. ‘‘ We are now planning to begin a comprehensive evaluation of gas potential deep under our existing fields.’’
Underpinning the focus on gas is a significant change to the political climate: greenhouse gas abatement, a major issue for all sides of politics. ‘‘ Gas,’’ Nolan says, ‘‘ can produce up to 70 per cent fewer emissions than coal in power generation.’’
With as much as 20,000MW of gas-fired generation under consideration for development in Australia over the next 20 years — most of it for the eastern states — and each 1000MW combined-cycle gas plant consuming 70 PJ a year, the power sector is now a major target for gas suppliers.
As the major political parties are committed to introducing an emissions trading scheme from 2011-12, natural gas will be a big beneficiary of charges imposed on energy users and power stations.
When carbon capture and sequestration becomes commercially viable, the Gippsland Basin operators might also stand to gain from systems that will deliver liquefied carbon dioxide from power stations for storage in depleted oil and gas wells.
Rob Young, ExxonMobil Australia government affairs adviser, is cautious, however, about this prospect. ‘‘ Gippsland Basin certainly has potential as a storage site for carbon dioxide,’’ he says, ‘‘ but the re-injection of CO into or near operational oil and gas fields also presents significant risk and integrity issues to personnel, production and infrastructure. These risks may not be manageable from either a technical or a cost perspective.
‘‘ Ongoing analysis is needed before the commercial and technical viability of any CCS project in the basin can be determined. Enthusiasm for the possibilities needs to be tempered by an acknowledgement that broad improvements in performance, cost and integrity of CCS systems and component technologies requires much further research.’’
He says the company has advised the Cooperative Research Centre for Greenhouse Gas Technologies on a feasibility study for storage of carbon emissions in the Gippsland Basin and, with Chevron and Shell, is also participating in a similar investigation in Western Australia as part of the development of the large Gorgon LNG project.
Young says suggestions that depleted reservoirs will be available in the Gippsland Basin by 2015 are ‘‘ overly optimistic’’. A timeframe of 2025 or later would be more realistic, he says, and even this would depend on how successful the joint venture is in extending the production life of its fields.
Sixty years or more of productive life is not a bad outlook for an area that in the 1950s had been deemed unworthy for exploration as one of the world’s roughest stretches of water adjacent to a coast where 140 unsuccessful wells had been drilled in the previous 40 years.