The fledgling use of floating LNG (FLNG) solutions that give operators access using pipeline infrastructure to remote gas field reserves that would otherwise be noncommercial is a recent phenomenon.

But the solution’s relative immaturity is not deterring operators from embracing it on a growing number of projects all currently on the drawing board in Southeast Asia.

One of its biggest supporters is Japan’s Inpex, with the company’s operated Abadi development offshore Indonesia having made strong progress throughout this year. Inpex has a 65% stake in the project as operator and has the apparent perfect partner in Shell—perhaps the industry’s leading proponent of FLNG technology—with the Anglo-Dutch major holding the other 35%.

The Abadi gas field is located in the Arafura Sea’s Masela Block in eastern Indonesia, lying in water depths ranging from 300 m to 1,000 m (984 ft to 3,281 ft). The block, covered by a standard production-sharing contract (PSC), is situated about 800 km (497 miles) east of Kupang, West Timor, and 400 km (249 miles) north of Darwin, Australia.

Abadi green light

Inpex recently received environmental permission from the Indonesian government for the project to proceed. The approval of the Environmental and Social Impact Assessment moves the project one step closer to development.

The Indonesian authorities only granted approval in late 2010 for Inpex’s Phase 1 development of Abadi, which includes the FLNG unit with a design capacity of 2.5 MMmt/year of LNG and 8,400 bbl/d of condensate. It is a true megaproject, with a price tag of about $14 billion.

Inpex is now conducting FEED work on the project, having last year demonstrated its commitment to the development by acquiring—along with Shell—the 10% stake held by Indonesia’s upstream player PT EMP Energi Indonesia after the latter agreed to divest its stake.

The first phase of Abadi was originally expected to come onstream in 2018, but Indonesia’s upstream regulator SKKMigas believes that target is not likely to be met, with 2019 a more realistic deadline.

Inpex also is currently seeking to extend its original 20-year PSC for the field, which will end in 2028, to a 40-year deal. The Jakarta government wants the extension to be tied to a request for Inpex to allocate some output for domestic use, with those talks still underway. Energy and Mineral Resources Deputy Minister Susilo Siswoutomo has said that the government wants at least 30% of Abadi’s production to be used domestically.

Shell’s FLNG know-how

Crucial to the Abadi Phase 1 development is the use of Shell’s proprietary FLNG technology. Shell has been advancing its technology since the mid-1990s; its high-profile Prelude FLNG development off Australia’s northwest coast is its flagship project.

Shell has stated several times in recent literature that it expects Prelude to be the first of many such projects, helping it to unlock natural gas resources including smaller and stranded fields as well as larger fields supported by several facilities.

Chilling natural gas to -162 C (-260 F) creates a liquid with 600 times less volume than in its natural state, with all the transportation advantages that come with it.

Citing the example of the Prelude FLNG vessel, Shell said the unit was “huge but compact.” Once complete, it will have decks measuring 488 m (1,601 ft)—the length of more than four soccer fields—and 74 m (243 ft) wide.

The Prelude unit will be the largest floating offshore facility in the world. The vessel is under construction at Samsung Heavy Industries’ Geoje Island yard in South Korea. It has been designed with double the capacity of the Abadi unit—the Prelude unit will have a production capacity of 5.3 MMmt/year: 3.6 MMmt/year of LNG, 1.3 MMmt/year of condensate and 0.4 MMmt/year of LPG.

Abadi Phase 2

Back on Abadi, however, with reserves originally estimated at 283.3 Bcm (10 Tcf) of natural gas, things are moving fast.

Based on those first reserve base estimates and the partners’ previous expenditure on Indonesian exploration, when Inpex and Shell originally examined their development options for the field, the use of an FLNG vessel was the natural choice to get production flowing. This was to recoup their initial investments as soon as possible even though the field was realistically close enough to shore to pursue a more traditional pipeline-to-shore solution.

Following further exploration and appraisal success since that time, the partners now have a proven and probable (2P) reserves base that is much higher, at 524.1 Bcm (18.5 Tcf) of gas. As a result, they are looking at larger scale options for Phase 2 than another FLNG unit could currently provide.

Hence Inpex and Shell are studying a more conventional concept for Abadi’s second phase. This involves an offshore fixed platform that would transport the gas via a pipeline to an onshore LNG plant with a proposed capacity of 5 MMmt/year of LNG. The onshore plant could be expanded to two LNG trains, both with a capacity of 5 MMmt/year.

This plan is currently being considered for location on the islands of either Aru or Tanimbar. The latter would only require 150 km (93 miles) of export pipelines compared to Aru Island, which would need about 600 km (373 miles) of pipeline.

Using this conventional development model, Inpex and Shell say they are confident that they can save up to 25% compared to using a FLNG solution for the full field development of Abadi.

Petronas pitches in

Malaysia’s state-owned Petronas also is pursuing its own FLNG solutions for its remote gas fields. The operator recently reported the lifting of the first topsides module for its PFLNG1 unit at the Daewoo Shipbuilding and Marine Engineering (DSME) shipyard in Okpo, South Korea.

The lifting of this first module marked a milestone for the facility, as it signifies that the PFLNG1 facility is near completion—something that has enabled Petronas to get a jump on its rivals to the point where it has said in a press statement related to the lifting of the first module that the unit would be “the world’s first FLNG facility in operation.”

The pioneer facility will be used to produce gas from the Kanowit Field located 180 km (112 miles) offshore Sarawak, Eastern Malaysia.

Technip and DSME were appointed to jointly develop the PFLNG1 facility, which again is smaller than Shell’s Prelude and Inpex’s Abadi units. PFLNG1 will have an LNG producing capacity of 1.2 MMmt/year, with the vessel having relatively diminutive dimensions of 365 m (1,197 ft) in length, 60 m (196 ft) in width and a height of 33 m (108 ft).

The PFLNG1 facility is only 14 m (46 ft) narrower than Shell’s Prelude unit in terms of width but 123 m (404 ft) shorter in length, so it will have only a third of the latter’s LNG production capacity (and around half that of the Abadi unit).

Once the construction and installation phases are completed in 2015, PFLNG1 will be moored on the field, although no firm first production date has yet been given by Petronas. “Once operational, the PFLNG1 will change the landscape of the LNG business and at the same time play a significant role in Petronas’ efforts to unlock and monetize gas reserves, especially in Malaysia’s remote and stranded fields,” Petronas said in a press statement.

A further unit also has been chosen by Petronas for its second planned FLNG project in its domestic waters. It issued a design, build and installation contract for the PFLNG2 unit earlier this year. The unit will be located in deepwater off the coast of Sabah, with the engineering, procurement, construction, installation and commissioning contract going to a consortium of JGC Corp., Samsung Heavy Industries Co. Ltd., JGC (Malaysia) Sdn. Bhd. and Samsung Heavy Industries (M) Sdn. Bhd.

The facility, if it proceeds as planned, will be moored on the Rotan Field in Block H and be slightly larger than the company’s first unit, with a planned production capacity of 1.5 MMmt/year of LNG.

FLNG not the only show in town

Southeast Asia also has a host of other development projects on the boil with not an FLNG facility in sight.

Petronas has made a $14 billion commitment to revamp its mature assets and develop marginal domestic fields via EOR techniques. The company’s executive vice president for E&P, Wee Yiaw Hin, said the sum was needed to undertake 10 EOR projects that the operator has in the pipeline.

It also has $337.1 million in hand for its E&P Technology Center to develop new EOR technology, added Wee, who sees the potential for the application of EOR techniques on 50% of Malaysia’s producing fields.

In Indonesia, meanwhile, SKKMigas expects that the much-delayed Banyu Urip oil field in the Cepu Block, East Java, will start full production in early 2015 as development work finally nears completion.

Development work at Banyu Urip was 92.5% complete as of mid-September, with the early production facility (EPF) already producing 30,000 bbl/d of oil, according to SKKMigas.

Output at the field, which holds an estimated 450 MMbbl of oil, will increase until it reaches a planned peak of 165,000 bbl/d by mid-2015. That peak is expected to last for about three years.

The project is 45% owned ExxonMobil, while Indonesia’s state-owned Pertamina holds 45% and regional player Badan Kerja Sama Blok Cepu has 10%.

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