Gas projects fire up

An array of large and small projects will push WA's petroleum production to 1 million barrels of oil equivalent per day for the first time next year.

The growing diversity of Western Australia’s oil and gas sector has been highlighted by the projects that have started production this year.

In May, Santos announced that oil production had commenced ahead of schedule and on budget from the $490 million Fletcher Finucane project in the offshore Carnarvon Basin.

Fletcher Finucane is projected to have an average gross production rate of 15,000 barrels per day in the first year.

One month later, Thai company PTTEP announced that its Australian arm had started oil production from the Montara oil field in the Timor Sea.

Production from Montara is projected to ramp up to 23,000bpd initially.

On a smaller scale, local company Empire Oil & Gas announced this week it had completed commissioning of its $34 million Red Gully gas project in the Perth Basin, two-and-a-half-hours drive north of the city centre.

Its gas is being supplied to major backer Alcoa, while the condensate goes to BP’s refinery at Kwinana.

A fourth opening, due to occur this week, will be at BHP Billiton’s $1.5 billion Macedon gas plant near Onslow.

Macedon will be the fourth major supplier to the domestic gas market, adding a degree of competition to the sector.

To put these developments in perspective, energy industry analysts Wood Mackenzie have ranked 25 oil and gas projects currently in production in WA (see table).

However the largest by far is the Woodside-operated North West Shelf venture, which is expected to produce at a rate of 564,000 barrels of oil equivalent per day during 2013 – about two-thirds of the state’s total petroleum production.

Wood Mackenzie analyst Australasia upstream research, Matt Howell, said WA production increased above 900,000 boe/d for the first time in 2010 on the back of peak production for the NW Shelf project and the start of production from BHP Billiton’s Pyrenees oil project.

WA production is set to pass 1 million boe/d in 2014, and then rocket to 2 million boe/d in 2019, due to the ramp-up of the Gorgon, Wheatstone and Prelude LNG development.

Mr Howell said that, before the NWS project came online in the mid 1980s, gas production contributed about 25 per cent of the state’s total production.

Since then, the mix has been roughly 50/50 between gas and liquids (where liquids includes condensate), but gas is trending upwards as more is brought onstream and oil production slowly declines from its peak in 2000.

A lack of recent, big oil finds meant that this decline was expected to continue, Mr Howell said.

The start of production from developments such as Santos’s Fletcher-Finucane and Apache’s Coniston-Novara and Balnaves projects over the next few years will slow the decline.

However gas will nonetheless make up more than 85 per cent of the mix from 2022.

A handful of major players will dominate future production, because they are sitting on large reserves.

The biggest of these is Chevron with ‘2P’ reserves of 26,101 petajoules, equivalent to 29 per cent of the state’s total gas reserves (see table next page).

Other big international players include Shell (16.6 per cent of the state’s total), ExxonMobil (11.3 per cent) and Japan’s INPEX (10.7 per cent), while Woodside holds 8.8 per cent.

Together, the five largest players hold about three quarters of the state’s gas reserves.

Their large gas reserves are reflected in their participation in most of the big liquefied natural gas (LNG) projects under way.

Woodside, Chevron and Shell are among the six equal owners of the NW Shelf venture; Chevron, ExxonMobil and Shell are major investors in Gorgon; Woodside and Shell are the major owners of the Browse gas fields; while Shell is the major owner of the Prelude development with Inpex as a minority owner.

The Gorgon and Wheatstone projects are primarily focused on the export market but they will also boost domestic gas supplies.

Gorgon is scheduled to start supplying the domestic market from 2016 while Wheatstone is due to start shipping gas to the South West in 2018.

DUET Group subsidiary DBP Development Group was selected this month to build infrastructure to link Wheatstone to the Dampier to Bunbury pipeline.

The $95 million project is expected to be complete by the end of next year.

DBP chief executive Stuart Johnson said the project would include a 30-year take-or-pay gas transportation contract with Chevron, to provide an initial gas transmission capacity of 337 terajoules per day, with expansion capacity up to 600TJ/day.

Another potential supplier to the domestic market is Buru Energy, which is aiming to develop gas resources in the Canning Basin inland from Broome (see page 16).

The biggest unknown facing the domestic gas market is the amount of supply after the NW Shelf venture’s current contracts expire.

Energy Minister Mike Nahan has repeatedly raised this as a concern.

“The largest supplier is the North West Shelf with 600 terajoues a day,” Mr Nahan told Business News in August.

“Will they renew those contracts when they come up due by 2020? I don’t know.”

The willingness of the Woodside-led joint venture to supply the domestic market may depend on whether the collective selling agreement is allowed to continue.

Gas buyers, led by Alcoa and other members of the Domgas Alliance, have vigorously opposed collective selling, which has been approved by the Australian Competition and Consumer Commission.

The other big player that could take advantage of any market disruption is Apache Energy, which operates the Varanus Island and Devil Creek domgas plants.

In the offshore sector, future growth will be increasingly dominated by floating LNG developments.

Shell is well into construction for its Prelude development, and this week finalised an agreement with Challenger Institute of Technology for training of the vessel operators (see page 18).

The Woodside-led Browse joint venture announced this month they had selected floating LNG technology to develop the fields.

Woodside said its joint venture participants – Shell, Mitsui, Mitsubishi, PetroChina and BP – had agreed that its recommendation to use FLNG was the most feasible development option.

It is likely that three FLNG vessels will be built, to fully exploit the neighbouring gas fields.

Another prospective development using FLNG technology involves ExxonMobil’s Scarborough gas field.

French company GDF Suez, along with local partner Santos, is working on an FLNG project for the Bonaparte gas fields off the northern coast.

Speaking at the SEAAOC (South-East Asia Australia Offshore Conference) in Darwin, GDF Suez Bonaparte general manager Jean-Francois Letellier said the timing of the project had slipped but emphasised the progress that had been achieved.

“This project is moving robustly and positively forward, towards the FEED gate at the beginning of next year,” he said.

Mr Letellier said the project team had front-end loaded the work on the project.

“In short, whilst ‘project execution’ is about doing the ‘project right’, pre-FEED is about ensuring you are doing the ‘right project’.

“So, rather than be schedule driven, we have been focused on doing a lot of work ‘up-front’ to make sure we are doing the right project, and this has moved our forecast FID date out from 2014 to the second half of 2015, and our expected first gas date from 2018 to 2019.”

The other expansion prospect for the industry is brownfields expansions of existing LNG plants.

A prime contender in this regard is the ConocoPhillips-operated Darwin LNG plant.

Speaking at the Darwin conference last week, Conoco executive Mike Nazroo talked up the rationale for a brownfields expansion.

“As an industry we must give serious consideration to development solutions that meet the cost challenges, which could impact our competitiveness in the future,” Mr Nazroo said.

“There are many exciting prospects being developed around Darwin, which will need an economic option through which to realise their potential.

“Darwin LNG may provide a unique and attractive opportunity to reduce downstream CAPEX and development costs for one or more of these prospects.”

Speaking earlier, he said the most significant cost benefit was the ability to use existing infrastructure for shared services.

“Not only has this infrastructure already been built, but in the case of Darwin LNG it was built nearly 10 years ago in a very different and much lower cost environment,” Mr Nazroo said.

“Construction of an additional train at DLNG would be simpler than a greenfield build, which should translate into a reduction in FEED engineering costs and time.”

Speaking at the same conference, Santos vice-president WA & NT, John Anderson, also talked up expansion of Darwin plant, in which Santos has a minority stake.

“Collaboration and cooperation in our industry is something the industry collectively has strived for over the years, and while not a silver bullet, it should be seen as a way to unlock our resources,” Mr Anderson said.

“And it is collaboration that I am talking about when I refer to Darwin LNG’s future.

“Whether it be backfill or expansion – the proximity of Darwin to Asia, and the ability to use existing infrastructure, should be considered by industry as a real, economic and cost competitive option for the development of nearby fields.”