Insights from Australia’s $200 billion LNG investment

Peter Moore's picture
Peter Moore, Professor, Curtin University
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Of the 10 new Australian LNG projects, all have faced cost and schedule challenges. Factors most often quoted include labour costs and productivity, remote locations, site-specific challenges, difficulties in accessing gas from coal-seam-gas fields, lack of cooperation between adjacent sites, and insufficient planning.

Extensive work is ongoing to improve outcomes for future projects. With labour challenges, there is a recognition of the need for enterprise bargaining agreements that are established pre-FID and last for the entire duration of the project. There are also many productivity improvement projects delivering better training, improved cross-project accreditation and collaboration, and better supply chain management using data analytics for processes ranging from scaffolding to LNG plant performance.

Site-specific challenges also provide lessons for the future. Gorgon was a major challenge, especially as materials arrival and installation varied from the original schedule. A better outcome is expected for Wheatstone, because the site is much larger and more accessible. Ichthys was also challenged by land access; piping gas 900km to Darwin addressed both access and timing issues.

Shell promoted FLNG as the best solution to developing remote Browse gas, based on the Prelude development. On a dollar per mtpa basis however, the cost saving were insufficient for a Woodside Browse FID. Further FLNG cost savings are being pursued.

One common theme around cost and schedule challenges has been the suggestion that more could have been done in the pre-FEED stage to plan and collaborate with other projects. Missed collaboration opportunities are easy to point to in hindsight, including Gladstone, Browse and in the Carnarvon Basin. However, given the existing complexity of these projects, including JV arrangements, project financing and pre-FID marketing, these situations are more complex than sometimes acknowledged.

Australia’s LNG development experience has varied across the country.

In the west, all major projects are offshore, in high quality conventional sandstone reservoirs. Big bore wells can often produce over 300 MMscfd. Pluto was developed with just 5 production wells. Production facilities are offshore, and at remote sites when landed for processing. Relevant governments are strongly supportive and regulators are well established.

This contrasts with the situation in the east, where Australia has converting CSG to LNG. Here, an LNG train may need 1000 times more wells. The activity is onshore, highly visible, ongoing, and in more populated areas. CSG can also involve fracture stimulation invoking community concerns. Fortunately, the Queensland government moved quickly to support the industry by establishing a regulatory framework. Aquifer models were built, and compensation flowed to landowners. Nonetheless, resistance to CSG in general and fracking in particular has led to numerous government inquiries and bans on activities in several states. With tens of thousands CSG wells still to drill, the focus on maintaining a licence to operate will remain intense.

Key lessons from the CSG boom have included the importance of early state government support, the difficulties in having immediate immaculate operations when everything is new and growth is huge, the need to communicate early and often with facts, the value in using independent respected voices, the need to get operational models established early including for land access, compensation, water treatment and aquifer studies and finally, the need to manage impacts on rural communities during the construction boom and the inevitable wind down.

Looking back, the $200 billion of LNG expenditure has created challenges along the way, but has left Australia with a substantial set of income-generating facilities that provide Australia with essential GDP growth.

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