West Coast Gas Bonanza Lights Up Australia’s Offshore Future

While the southern coast of Australia continues to tick over with relatively small but steady activity, and with New Zealand searching via licensing rounds offering frontier acreage to inject life into its somewhat stagnating and already modest oil and gas scene, Australia’s western shore is a totally different story.

With operators such as Woodside Energy, Chevron, ExxonMobil, Shell, and BHP Billiton increasingly focused on either expanding established shallow-water LNG schemes or developing mostly deepwater mega-projects offshore Western Australia to meet continually expanding gas demand – particularly from Asia – the result has been a huge upsurge in current and predicted spending. An estimated US $120 billion has been committed or is under consideration for these projects.

Western Australia’s lineup of LNG projects currently under way represents more than $120 billion in terms of projected expenditure. (Image courtesy of the Department of Mines and Petroleum, Government of Western Australia)

These newer breed of projects now emerging also are proving to be as pioneering and challenging technologically as anywhere else in the world, with floating LNG (FLNG) solutions, deepwater tension-leg platforms (TLPs), and long-distance subsea tiebacks to onshore LNG plants currently either under way or on the drawing board. All of these are leaning on knowledge and experience gained from the world’s established offshore basins, with most of the operators and contractors drafting in experienced staff from elsewhere to ensure sufficient knowledge and technology transfer.

This also has lead to significant growth in required infrastructure and logistical support in and around Perth, with many manufacturers and service and supply companies either establishing or expanding their presence in the area to position themselves for a slice of what looks set to be a long-term growth market.

Major public investment in recent years in the Australian Marine Complex (AMC) just south of Perth has given service companies access to common-user infrastructure, including a recently commissioned $60 million floating dock measuring 325 ft by 174 ft (99 m by 53 m), and capable of lifting vessels up to 12,000 metric tons. This will enable underwater subsea structure treatment, while a new $35 million service and supply base is being developed to support offshore projects with a service wharf to accommodate roll-on/roll-off vessels and a 473,612-sq-ft (44,000-sq-m) staging area. The AMC, established in 2003, now has more than 100 businesses located there.

Work also is under way on the construction of a “subsea cluster” facility, which is aimed at helping to create a strategic network of service and supply capabilities for the E&P industry, and targeting both the domestic and wider Asia Pacific subsea markets.

Natural gas has become increasingly important for Australia, both as a source of export income and as a domestic energy source. Approximately 50% of the country’s gas production currently is exported, with nearly all (approximately 96%) of conventional gas production coming from three petroleum basins – the Gippsland Basin (Victoria), the Cooper-Eromanga Basin (Central Australia), and the Carnarvon Basin (northwest Western Australia).

The latter dominates, accounting for 64% of national production in 2008 to 2009, with the Carnarvon Basin accounting for 99% of state gas production.

Oil is a different story since Australia is a net importer of crude. The country’s largest petroleum-producing basin also is the Carnarvon Basin.

The FLNG design is planned to be used on the Prelude field, followed by another on the Greater Sunrise project. (Image courtesy of Shell)

Recent forecasts state that Australian oil production between 2010 and 2020 will fall by 29.21%, with crude volumes peaking in 2013 at 640,000 b/d before declining to 395,000 b/d by the end of the decade.

Gas production, however, is expected to soar from an estimated 1.77 MMcf in 2010 to a possible 3.88 MMcf by 2020. With 10-year market demand growth domestically of 30.52%, this essentially means an export potential which will rise from an estimated 812 Mcf to 2.65 MMcf, all expected to be LNG. Western Australia currently accounts for nearly 9% of global LNG production, but that figure certainly will rise as a handful of major developments are brought onstream within the next few years.

Flagship LNG mega-projects such as the Chevron-operated $37 billion Greater Gorgon project are leading the way. One of the largest single-resource investments in the world, Chevron is partnered by ExxonMobil and Royal Dutch Shell on this development. The project entails subsea production from several shallow and deepwater fields with reserves estimated at 40 Tcf of gas. Processing facilities will produce 15 MMtpa of LNG for export and 300 terajoules of gas per day for domestic consumption.

Greater Gorgon also is breaking new ground in greenhouse gas management through CO₂ injection into underground formations.

Jim Blackwell, executive vice president, Technology and Services, at Chevron, said, “Looking at Gorgon, it’s the centerpiece of our growth story. Everything about this project is huge: resources, production, and infrastructure. The Gorgon and Io/Jansz gas fields hold more than 40 Tcf of gas, the equivalent of 7 Bbbl of oil.”

A total of $25 billion in contracts already have been awarded on Gorgon.

Gorgon’s project workscope covers a three-train 15 MMtpa LNG facility, a domestic gas plant and maximum production of 2.6 Bcf/d of gas and 20,000 b/d of condensate, with startup expected in 2014. The newbuild Atwood Osprey rig is now complete in Singapore, the operator said, and is due to start drilling development wells on Gorgon later in 2011.

“Our first three trains at Gorgon are expected to produce 450,000 boe/d,” Blackwell said, adding that a final investment decision (FID) on a fourth train for Gorgon would be reached before the end of 2013.

That decision will have been helped by a string of 10 discoveries made by Chevron over the past 18 months – most recently with its Orthrus-2 find in the WA-24-R permit encountering 243 ft (74 m) of net gas pay, of which 102 ft (31 m) of net gas pay were encountered in a deeper, previously unexplored target interval. At the end of 2010, Chevron’s estimated total resource for the Greater Gorgon area was almost 60 Tcf, he added, with enough potential for a fifth train for Gorgon.

Petrobras quietly stepped into New Zealand’s frontier deep waters for the first time in 2010, taking 100% of Block 2 in the Raukumara Basin offshore North Island. (Image courtesy of Petrobras)

Chevron’s other key project in the area is its $23 billion Wheatstone LNG scheme. An FID on Wheatstone’s first and second trains is expected to be taken later this year on what will be a two-train, 8.9 million metric tons per year LNG facility planned to start up in 2016 at a forecast rate of 260,000 boe/d. The contracting process already is under way on Wheatstone, which is approximately 60 miles (100 km) south of Gorgon.

The project consists of the development of four fields – Wheatstone, Iago, Brunello, and Julimar – via an offshore processing platform that will pipe raw gas to an onshore plant.

Chevron says Wheatstone also is well-positioned for a third LNG train and further expansion.

Another equally active player offshore Western Australia is Woodside Energy, which is spending $12 billion on its Pluto LNG project, while also proceeding with the estimated $30 billion development of its Browse LNG scheme, among others.

Pluto is the most advanced, with an annual capacity of 4.3 Mtpa and due to come onstream in August 2011. The operator also already is considering significant future expansion of Pluto, while juggling plans for a $5 billion redevelopment on behalf of the long-established North West Shelf Venture of its North Rankin field to extend its producing life to at least 2040.

Woodside’s managing director and CEO Don Voelte said, “We see no slowing down of LNG demand. The world produced about 210 million tonnes of LNG in 2010. Demand in 2025 is forecast to range between 390 million tonnes and 460 million tonnes. This is an increase of around 85% to 120% from current levels.

“From 2011 and going out toward 2016 and 2017, the supply of LNG appears to be tightening, and this is very supportive for LNG prices. Beyond 2017, the market is banking on projects getting up, which we currently rank only as ‘possible’ developments,” he said. “Put simply, if you have any spare LNG over at least the next 15 years, you will easily find a willing buyer. And those buyers are keen to ensure they have Australian LNG in their portfolios.”

Because of this, Woodside has been quick to progress its estimated $30 billion Browse LNG development, which is a world-class project also entailing one of the world’s most significant deepwater schemes.

Browse is a joint venture (JV) between Woodside as operator, BHP Billiton, BP, Chevron, and Shell, which Woodside describes as a “game changer” for the company, essentially because Browse will double the company’s current equity share of LNG production.

The overall project – if it receives an FID as planned mid-2012 – will include three TLPs (two initially and the third in a later phase) in deep water, as well as two bridge-linked central processing platforms in approximately 328 ft (100 m) water depth, more than 746 miles (1,200 km) of subsea pipeline infrastructure, and a three-train LNG facility 202 miles (325 km) onshore.

The TLPs will process gas and condensate from three fields in the Browse Basin, starting with the Brecknock and Calliance fields and then the Torosa field. The fields are estimated to contain a combined contingent resource of 13.3 Tcf of dry gas and 360 MMbbl of condensate.

According to Voelte, “Browse is just tracking beautifully, rolling from basis of design into front-end engineering and design (FEED), in keeping with the timetable set by the state and federal governments.”

A handful of contracts were issued recently for key parts of the project. Fluor Corp.’s Fluor Offshore Solutions unit was awarded a FEED contract in partnership with McDermott International for the central gas processing facility including steel jackets, a compression platform, and a utilities accommodation platform. Fluor teamed with McDermott for the steel jackets design and float-over installation. Work is under way, and completion is expected by the end of 2011.

The two initial TLP dry-tree units are the subject of parallel FEED studies being conducted by Aker Solutions and Modec. An engineering, procurement, construction, and installation tender will be submitted mid-year, with expected contract award by the end of 2011.

Both floating production facilities, which will be configured for subsea tieback to the central processing complex, also will pioneer the first use of TLPs offshore Australia. “We look at this as an opportunity for Aker Solutions to be instrumental in bringing TLP technology to Australia,” the company said.

Offshore gas liquefaction – otherwise known as FLNG – is a technology that has just barely moved off the drawing board and conceptual studies to become a firm project option, and Western Australia is at the forefront of its first planned use.

One of its main proponents is Shell with its plans for the Prelude project, also in the Browse Basin. The project is scheduled for an internal FID before the end of 2011 and would be the world’s first FLNG facility in action.

The operator currently is in the FEED phase for the unit, which is being designed to produce 3.6 million mt/year of LNG, 400,000 mt/year of liquefied petroleum gas, and 1.3 million mt/year of condensate. First LNG is expected to flow by 2016.

A consortium of Technip and Samsung Heavy Industries signed deals with the Anglo-Dutch major in 2010 for the Prelude FLNG project, covering the FEED and fabrication terms if it proceeds.

Following closely on its heels is another FLNG project in which Shell is involved – the Woodside-operated Sunrise LNG JV. The Greater Sunrise fields, which straddle the Australian and East Timorese maritime border, are estimated to hold more than 5 Tcf of gas and 226 MMbbl of condensate.

The Sunrise JV recently selected a development concept to produce the reserves using FLNG technology and said the project has robust economics. However, formal government and regulatory approvals still are required before it is considered a firm project, as East Timor’s government prefers an onshore plant for this high-profile, politically charged development.

However, with estimated costs for that option coming in approximately $5 billion higher, the floating liquefaction option is expected to win. Preparations already are under way for basis of design and FEED stages, Woodside says.

FLNG technology will become an increasingly employed solution for commercializing remote or “stranded” gas reserves, and Australia is primed to be at the forefront of its use.

More conventional floating oil-production projects will continue to be employed there.

Recent examples of smaller yet substantial floating production developments include BHP Billiton’s $2 billion, 96,000 b/d Pyrenees oil field in the southern Carnarvon Basin and Apache Energy’s $700 million, 40,000 b/d Van Gogh oil field in the Exmouth Basin. Both began production in early 2010. In October 2010, Van Gogh was shut in for unexpected repairs to be carried out to the Ningaloo floating production, storage, and offloading (FPSO) unit, but came back onstream earlier in 2011 and has been producing routinely.

Operators such as Woodside continue to hoover up reserves around their other existing floating production projects offshore Western Australia, with the company likely to tie back its deepwater Laverda oil discovery (40 MMbbl of recoverable reserves) to one of its nearby producing FPSOs in the Exmouth Basin on fields such as Vincent, Stybarrow, and Enfield. However Laverda still could proceed as a standalone floating production project, depending on data from appraisal wells due to be drilled in 2Q 2011. An FID decision will be made by the end of 2011.

Woodside also confirmed that late last year it drilled successful wells in the Enfield area, with the Cimatti-1 and Cimatti-2 wells drilled in approximately 1,805 ft (550 m) water depth in Block WA-28-L. Cimatti-1 hit a gross oil column of 49 ft (15 m), while Cimatti-2 hit a 23-ft (7-m) thick oil-bearing sand. Cimatti lies close to the Nganhurra FPSO in the Enfield field, which currently is producing approximately 31,000 b/d, due to a recent infill drilling program. A 4-D seismic shoot will further evaluate other opportunities.

Cimatti likely will be a subsea tieback to Enfield, Woodside says, with an FID to be made in 2011 for a planned production startup in mid-2013.

ExxonMobil’s development of the deepwater Scarborough and Thebe gas fields is another Western Australian LNG project.

The Greater Gorgon, Wheatstone, Pluto, and NWS projects are surrounded by a substantial number of established discoveries such as Scarborough and East Artemis, along with many other smaller discoveries and prospects that will eventually feed future expansions of the main LNG projects either already established or under development. (Image courtesy of MEO Australia)

The fields will be developed with partner BHP Billiton when both agree how best to do so commercially. Scarborough then will be another major offshore project involving between $15 billion and $20 billion of investment. Whether the 10 Tcf of estimated recoverable reserves in license WA-346-P will be tied into one of the existing LNG developments in the area, such as Pluto or Browse, or as a standalone greenfield project still remains to be seen. Concept selection studies are progressing, and site geotechnical survey work also is under way, with planning for a FEED stage to get under way before the end of 2011.

Australia has many unexplored frontiers offshore its huge coastline. Although acreage releases have focused on Western Australia, with several rounds either under way or due to close this year, operators also have been looking to the continent’s south coast in particular.

BP recently was awarded four deepwater blocks in the Ceduna Sub-basin within the Great Australian Bight, covering approximately 9,266 sq miles (24,000 sq km). “This is a material and early move into an unexplored deepwater basin,” said Mike Daly, executive vice president of Exploration for BP.

“The Ceduna Sub-basin is a very exciting new exploration area for BP,” added Dr. Phil Home, managing director of BP’s Australian upstream oil and gas business. “Our experience tells us that the geology has a high potential for containing hydrocarbons.”

Approximately 4,402 sq miles (11,400 sq km) of 3-D seismic survey work could take place in 2011 and 2012, with up to four wells to be drilled in 2013 or 2014.

While many offshore markets in Southeast Asia are showing signs of significant growth, Australia’s sector – driven by its explosion of activity offshore the west coast – is in the midst of a transformation from a province with potential to a world-class gas powerhouse.