JAKARTA – Indonesian Energy and Mineral Resources Minister Arifin Tasrif ‘s reference to using hybrid offshore and onshore development systems in the Masela liquified natural gas (LNG) project raises speculation that plans for laying a 170-kilometer pipeline across a 3,000-meter-deep undersea trench may be either delayed or abandoned altogether.
Majority Japanese stakeholder Inpex Corporation is accelerating progress on the 9.5 million tonne per year Abadi LNG plant in the remote Arafua Sea, with a final investment decision now due in mid-2026, at least seven years behind schedule.
The 13 trillion cubic feet (TCF) project has regained some momentum since Indonesian and Malaysian state oil firms Pertamina and Petronas recently teamed up to buy the 35% stake in the project previously held by Royal Dutch Shell, one of the global pioneers of floating LNG technology (FLNG).
Shell eventually withdrew from Masela after the then-newly installed Joko Widodo government insisted in 2015 on converting it from an offshore to an onshore operation on the Tanimbar islands, north of the Indonesia-Australia maritime border.
The US$650 million investment transaction will be settled in two payment tranches – $325 million in cash and an additional $375 million the Pertamina/Petronas consortium will pay at the time of the final investment decision.
Then-chief maritime minister Rizal Ramli persuaded Widodo to switch to an onshore development, based on the benefits he insisted it would bring to a small archipelago – now an occasional cruiser liner destination – and the rest of Maluku province to the north.
Few detailed studies appear to have been made to explain those benefits, compared to what the offshore option might offer in terms of supplying gas straight from an FLNG to a string of power stations across undeveloped eastern Indonesia.
It remains unclear at this stage whether natural gas will be used to power the new LNG plant and how many of the 10,000-strong Abadi work force will come from Maluku in under-developed eastern Indonesia, where nickel has spurred recent economic growth.
Experts say the now-planned use of a hybrid form of a floating LNG concept utilizing at least one 170,000 cubic meter Floating Storage Regasification unit (FSRU) for the Masela project suggests it may fill an anticipated supply gap before the completion of the pipeline.
Some analysts even question whether the pipeline will be laid at all under a new government to be installed in 2024 given the difficulties spanning the trench, which runs along the western and southern coasts of Sumatra and Java and marks one of the most active fault lines in the world.
At least 80% of an FSRU would be built at shipyards in China, South Korea or Singapore, leaving little work for local companies, including state-owned enterprises which have benefited from many state construction contracts over the past decade.
The only two FSRUs currently operating in Indonesia – in Jakarta Bay and off the southern Sumatran province of Lampung – are being employed for downstream distribution direct to LNG-run power plants, not for upstream ventures.
Critics have long claimed an onshore facility would favor politically-wired business interests in Jakarta who are either suspected of acquiring property on the main Tanimbar island of Yamdena or stand to win some of the onshore project’s lucrative work contracts.
The LNG facility will be built on a 600-hectare site on Yamdena, which covers 3,000 square kilometers and has a mainly Christian population of 123,000, most of whom are either fishermen or subsistence farmers.
Masela will become Inpex’s second largest management asset after the Ichthys LNG project on Western Australia’s Northwest Shelf, where the company is pondering a third production train at its 8.9 million tonnes per annum LNG facility.
Inpex chief executive Takayuki Ueda said last month that the company planned letters of intent with potential LNG customers enabling it to secure approval from Indonesian authorities for a revised Plan of Development (POD).
Initially, Inpex and Shell had planned to sign the POD at the G20 Summit in Osaka, Japan in 2019, but it was already clear the British multinational was on its way out, deterred by the government’s change of concept.
In addition to the FSRU, the Masela plant will also incorporate carbon capture, utilization and storage (CCUS) technology, expected to cost an additional $1.2 to $1.4 billion.
The employment of CCUS technology aligns with the government’s clean energy transition program, ultimately resulting in a more environmentally friendly LNG product for state power utility Perusahaan Listrik Negara’s (PLN) network of six large LNG-fired stations, which contribute nearly 8,000MW of PLN’s 53,000MW main Java-Bali grid.
While still a fossil fuel, natural gas will become the necessary transitional fuel between coal and renewables, including geothermal, solar and wind, which at this stage of their development don’t readily lend themselves to reliable baseload power.
More than 70% of the Java-Bali grid remains dominated by coal supplies from Kalimantan and Sumatra. Only 7.7% of the gridrelies on renewables, mostly geothermal and hydro, with installed solar capacity amounting to just 300MW.
According to experts, FSRUs require some onshore and port infrastructure, but not the extensive berthing, piping, storage tanks and associated infrastructure required for conventional onshore LNG terminals, of which Indonesia currently has three still functioning.
An FSRU’s more recent integration into upstream gas projects can offer various benefits, according to one Jakarta-based oil and gas consultant with long experience in Indonesia’s rich gas fields.
“It’s important to note that using an FSRU upstream requires careful planning and consideration of technical, economic and regulatory factors,” he says. “Their integration involves designing suitable connections, safety measures and procedures to ensure efficient and safe gas handling and storage.”
Among its upstream applications, an FSRU can be deployed to temporarily store excess gas produced during peak production periods, preventing wastage and allowing for controlled distribution when production rates decrease.
In addition, by connecting an FSRU to an onshore LNG facility, the associated gas can be collected and stored, then re-gasified and used for power generation or other purposes, reducing the need for gas flaring.
Upstream gas projects in remote or economically marginal locations, such as Masela, could also use an FSRU to meet challenges in building permanent onshore infrastructure. In such cases, it can be a cost-effective way of storing the gas before it is transported to consumers or larger pipelines.
Experts point out that because traditional onshore gas processing facilities can take several years to plan, design and construct, an FSRU can be deployed rapidly to meet tight project deadlines and take advantage of favorable market conditions.
If the upstream project is located near the coast, an FSRU can also serve as a temporary LNG expert terminal,allowing the gas to beliquefied and stored there before being transferred to giant LNG carriers for international export.
The Masela project is showing progress as BP’s long-delayed, third Tangguh production train in West Papua ramps up production since its inauguration on July 26, making it the country’s largest LNG processor ahead of Kalimantan’s 45-year-oldBontang plant.
The first LNG moved from the third train on September 13 and a BP spokesman says he expects it to become fully operational by the end of the year, effectively doubling Indonesia’s LNG production to 30.5 million tonnes by 2027 and giving the industry a new lease on life.
About 75% of production will be delivered to PLN, which plans to replace many of its old coal-fired power stations with gas and, to a lesser extent renewables, by 2040.
More good LNG news was revealed recently by Italian major ENI, which announced the discovery of five trillion cubic feet of gas and 400 million barrels (MMBLS) of associated condensate from the Geng prospect, which was first identified by Indonesian junior Black Platinum in the North Ganal production sharing contract (PSC) block 85 kilometers off East Kalimantan in 2011.
The third largest find in the Kutai Basin, North Ganal lies to the south of the Indonesia Deepwater Development (IDD) project recently acquired from Chevron, the latest US oil major to quit Indonesia, and will now make IDD a much more attractive commercial proposition.
Black Platinum activated the North Ganal block through a joint study with ENI, with the Italian firm becoming partners in 2011. Initially, the Italians weren’t interested in Geng, choosing instead to drill what turned out to be a marginal prospect in 2012.
Last July, Eni finally purchased 62% of management rights to five gas fields covered by four separate PSCs previously held by Chevron in the Makassar Strait. Now, IDD working areas are being incorporated into North Ganal with future production helping improve nearby Bontang’s future supply uncertainty.
