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Mr Agostini explained that Woodside Petroleum operates through its wholly owned subsidiary Woodside Offshore Petroleum on behalf of a Joint Venture which includes in various combinations, Woodside Petroleum, Shell, BP, Chevron, BHP, Mitsubishi and Mitsui. Woodside, once a small Australian company, became the operator of a large exploration area and significant gas discovery. It has brought together a joint venture of some of the largest oil companies in the world to develop the project while retaining its leadership role.
The North West Shelf project involves of combined investment at over A$10 billion. In addition the project's customers have made major investments in terminals in Japan and the Dampier to Bunbury natural gas pipeline in WA.
It is important to realise that LNG provides supply diversity to some countries, energy efficiency in power generation and exceptional environmental performance. These benefits enable LNG to justify a premium over other fuels to offset the high costs of gas liquefaction, storage, and shipping.
To their advantage were the quality and reliability of supply and the political stability of Australia.
When Woodside first negotiated its non recourse loan in 1980, it was the largest non recourse project financing in the world. It borrowed money against just gas in the ground and negotiated supply contracts. The total facility was US$1450 million, with a group of seven lead managers syndicated through some sixty-three banks. At that time the oil price was around US$32 per barrel. The LNG project commitment took place in 1985 and oil prices fell dramatically leaving the conclusion that had project commenced any later, it might not have gone ahead.
Nevertheless the joint venturers used ingenuity to ensure survival with the collapse of oil prices. For example they adopted a gas turbine/air cooling combination in place of steam turbine/water cooling which reduced plant costs by about $A1 billion.
There have been some extremely expensive surprises. The nature of the subsea soil in this area of the North West Shelf is highly unusual and standard techniques were not effective. Repairs to platforms and foundations on North Rankin and Goodwyn cost some $650 million (with insurance compensation for Goodwyn).
Offsetting these unexpected costs were also gains.
In 1980 it was thought three platforms were necessary with North Rankin costing say $1.5 billion begin required some 5km north of North Rankin A in order to be able to drain the reservoirs adequately. With the requirements for gas being initially lower than forecast, the North Rankin platform was deferred. Later, the development of extended reach drilling meant the platform was not necessary.
North Rankin is currently capable of producing 1815mcfc (which is some 50 per cent above its initial design capacity) though a series of debottlenecking projects. The reservoirs in North Rankin and Goodwyn have performed exceptionally well with upgraded reserves with greater quantities of condensate than anticipated. As a result, the platform design incorporates gas recycling to achieve accelerated condensate production and ultimately higher recoveries.
The other aspect of the reservoirs has been the exceptional well deliverabilities typically in excess of 150mmscf/d reducing the number of wells required to support production requirements.
The onshore plant too has generally performed well and above capacity. The Domestic Gas plant has shown that it is capable of some 50% greater throughput than design and the LNG plant has been debottlenecked to improve its capacity by 25% above the original design. Though the design capacity of the LNG plant was 6 mtpa, with debottlenecking contracts have been undertaken on a take or pay basis for 7.5 mtpa..
Many technical innovations were built into the North West Shelf both upstream and in the processing plants on the Burrup Peninsular.
Today, even greater cost savings can be achieved by installing fewer but larger gas turbines in an LNG train, and using fewer, larger heat exchangers.
Considerable progress has also been made in better integrating utilities using larger storage tanks and by using larger ships to gain economies of scale in product movement. In order to remain competitive, future projects will need to be able to adopt some or all of these innovations.
The time frame for bringing Australia's next LNG expansion on-line ranges across 2003-2005. By that time, a Japanese market requirement for at least two new Australian LNG trains is foreseen with unit train size now taken as 3.5 million tonnes per year deliverable.
Enhanced development rates in Australian resource industries will also lead to major increases in domestic gas demand over the next five to ten years.
The North West Australian offshore comprises three large areas, all of which are known to contain gas. The Carnarvon Basin contains two sub-basins; one in the south operated by WAPET and containing the Gorgon and Chrysaor fields, and the other, further north, operated by Woodside, and holding the Goodwyn, Perseus, North Rankin, Angel and Lambert fields.
These north Carnarvon basin fields typically contain high contents of LPG and condensate - a particularly valuable property when it comes to LNG project economics. Although more appraisal work is required, potential ultimate reserves in the North West Shelf Venture probably exceed 30 TCF.
Further north, the Browse Basin is highly prospective containing the Brecknock and Scott Reef fields with combined reserves anticipated at between 15 and 20 tcf.
The Timor Sea region has become markedly more promising through discoveries in recent years and embraces at least two interesting gas prospects: Bayu/Undan in the Zone of Co-operation and Sunrise/Troubadour in Northern Territory water. The ultimate reserves figure, while tentative, could well exceed 10 TCF.
Of these the Carnarvon Basin, particularly the northern sub-basin is the most likely to be developed with favourable gas/liquids quality and existing infrastructure. This projection is helped by the projected shortfall in supply in east Asia with Korea already requiring 500 Tj/day.
Domestic demand was growing too. Direct Reduced Iron projects, with BHP already committed to 150Tj/day will lead to a doubling of the market in ten years. Of course too the Goldfields Gas Pipeline will contribute beginning with a further 80Tj/day.
Though there is ethane gas, total gas production is not yet sufficient to support a petrochemical venture (that might require around 80Tj per day). Mr Agostini thought that within 5 to 7 years there may be adequate supplies of ethane to support a project. Much of the projections depends on their competitiveness with other regions with often lower construction costs and lower taxation regimes. Mr Agostini reminded the audience that there is of course competition from overseas, mainly Malaysia, Oman and Qatar. Though Australian LNG has the advantage of lower manufacturing costs, other costs, notably construction costs serve to erode that advantage.
Mr Agostini closed his presentation saying he was very optimistic about the future of gas projects and downstream projects in Western Australia.
A vote of thanks from Mike Allenby, Chairman of the WA branch of the Australian Consumer & Specialty Products Association closed this most illuminating presentation about the most significant resource project in Australia.
Recorded by Remco Van Santen Director ACTED
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