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Update for 18 October 1996. As recorded in the "West Australian" newspaper, Woodside confirmed it planned to spend A$6bn to expand LNG production from 7.5mtpa to 14mtpa from 2003.
Expansion is to be based on gas controlled by the shelf partners and did not include gas from the competing WAPET consortium so that it will require the development of new gas reserves. WAPET, which shares common shareholders plus Texaco and Mobil, are still hoping for a joint development involving gas from their Gorgon field.

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Woodside Offshore Petroleum - an exciting future

Woodside manages Australia's largest resource development. It began in 1954 naming itself after a township in Gippsland Victoria. Today it's marking the beginning of a new phase of development moving its corporate headquarters from Melbourne to Perth. With that Eddy Wajon, Secretary of the RACI Industrial Chemistry Group introduced Mr David Agostini, General Manager Operations, Woodside Offshore Petroleum Pty Ltd with the topic of the 15th CIP seminar.

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.


bulletIn 1963 Woodside acquired permits over a vast area of the North West continental shelf off Western Australia. bulletMajor gas discoveries in the early 1970's saw the birth of the North West Shelf project, the largest and most ambitious resource development project ever undertaken in Australia. bulletEighteen years passed between the finding of gas at North Rankin and the first delivery of LNG to Japan. The export of Liquefied Natural Gas (LNG) began in 1989. Twenty year take-or-pay contracts were secured for the supply of LNG to eight major Japanese power and gas utilities. bulletDelivery of natural gas to WA commenced in 1984, under long term contracts with the State Government owned energy utility. (The first gas contract was signed in 1980). bulletThe North West Shelf project has produced condensate, a light oil, in association with natural gas since the mid 1980's. bulletIn November 1993, the participants decided to install LPG processing, storage and ship loading facilities adjacent to existing onshore facilities. The development was completed in November 1995 at a cost of A$305 million with a capacity of around 800 000 tonnes per annum. bulletIn 1993 it was estimated the investment impact of the North West Shelf project was a sustained lift to Australia's GDP of more than 1%, net employment of 80,000 and exports by 3.5% (research by Clements and Grieg of the University of Western Australia). bulletThe project's first crude oil development, based on Wanaea and Cossack oil fields, commenced operations in late 1995. In late 1995 the North West Shelf overtook Bass Strait as Australia's premier oil and gas producing area.


The project's gas based assets (under Woodside management) includes two offshore production platforms, a 132 km submarine pipeline to the coast, a complex LNG processing plant, LPG extraction facilities, domestic gas plant, storage tanks and ship loading facilities. In addition the project operates a fleet of 8 dedicated LNG tankers to service the Japanese LNG contracts.
The Burrup Peninsula receival and processing plant
The North West Shelf project installation on the Burrup Peninsula

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.

World market

The world's first commercial LNG export was started in Algeria in 1964 with a modest capacity of 0.6 mtpa. Today, current world export capacity is more than 70 million tonnes from 10 plants. The market is dominated by Japan which is the largest single importing country representing 65% of worldwide demand for LNG.

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.

Luck and performance

The North West Shelf has been built on a reputation for high levels of reliability. Liquefied gas is expensive and inefficient to store in large quantities so producers and consumers hold minimal inventories. This requires a manufacturing level of reliability that is not commonly found outside of utilities. This was a challenge to the North West Shelf given the poor reputation of Australia during the 1980s for industrial harmony. The LNG buyers were extremely concerned about Woodside's ability to maintain uninterrupted supply in this environment. A lot of effort has gone into developing employee relations in Woodside and consequently there has not been any interruption to supply in the seven years that the LNG plant has been in operation. Woodside has built up a culture of an organisation with a genuine intent to incorporate all employees who are engaged on the same basis as professional staff.

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).

Goodwyn A platform
Goodwyn A platform.

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 A platform
North Rankin A platform.

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 future

In the past, the absence of infrastructure and the high cost of building in remote locations in the North West of Australia inhibited new investments. Today the shift in the hydrocarbon industry's focus to the north west and north of the country is assisted by the evolution of oil and gas infrastructure and services.

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


One Terajoule (ie. 1000 gigajoules) per day approximates to around 7 200 tonnes of gas per year.

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