COLUMN | Part two: the dash for gas in Asia – Indonesia and Vietnam [Offshore Accounts]

In part one, we looked at how the unreliability and untrustworthiness of the Kremlin as a gas supplier has driven European states to seek domestic gas supplies. In 2027, Romania will become the largest gas producer in the European Union, and Turkey aims to produce more gas itself than it imports from Russia in a similar time frame.

Now we look at how Indonesia is making is finally moving ahead with its large portfolio of offshore gas projects, which will drive drilling rig utilisation and offshore support vessel (OSV) demand.

Unfortunately for international players, Indonesia is a cabotage market where Indonesian flag operators dominate, headed by Wintermar and Logindo.

Indonesia finally firing on all cylinders

Indonesia is at the heart of the dash for gas, with the long-delayed Abadi LNG project due to receive investment approval shortly in the remotest area of the Arafura Sea, ENI’s plans to feed more gas into the Bontang LNG plant from its deepwater Geng North project off Kalimantan province on the island of Borneo, and Genting’s Kasuri project in West Papua province, where the Malaysian casino-plantation-energy conglomerate announced plans to build a 1.2 million tons per annum (MTPA) floating LNG facility at Wison in China earlier this year.

Genting says that the target sail away date for the FLNG unit from Zhoushan shipyard will be in second quarter of 2026. Around 230 million standard cubic feet per day (mmscfd) of natural gas will be supplied to the FLNG facility for 18 years, whilst another 101 mmscfd of natural gas will be sent to an ammonia and urea plant to be built onshore nearby in West Papua. Indonesia will thus benefit from both export revenues from the LNG and from domestic fertiliser production.

Mubadala and Harbour strike gas in Andaman Sea

Also in the potential project pipeline are large gas discoveries in the Andaman Sea in the far west of Indonesia. Abu Dhabi-headquartered Mubadala Energy as operator, in partnership with Harbour Energy, confirmed in September that it had completed South Andaman drilling campaign with the drillship West Capella, with the successful appraisal of the Layaran gas discovery.

The exploration and appraisal campaign, which included Layaran-1, Tangkulo-1, Layaran-2 and Layaran-2ST1 in South Andaman, demonstrated the potential for several hundred bcm of gas reserves in the deepwaters off Aceh in Sumatra.

At the same time, Mubadala and Harbour announced they had been awarded the Central Andaman licence by MIGAS, the Indonesian oil and gas regulator, as part of the latest Indonesian licensing round. This opens up more drilling targets for them in the same basin.

Whilst Mubadala has expressed a desire to “fast track” the development of the South Andaman discoveries, the reality of the remote and deepwater location, the limited domestic gas demand in Sumatra and the byzantine Indonesian bureaucracy mean that I doubt first gas will be achieved before the 2030s.

But add it to the future project list. And add a new project to the “in progress” listing.

BP approves US$7 billion Tangguh LNG expansion

Last Wednesday, BP’s CEO met with the president of Indonesia, Prabowo Subianto in London. Both were delighted to announce they had approved a US$7 billion carbon capture, utilisation and storage (CCUS) project for BP’s Tangguh LNG project in West Papua. BP is 40 per cent operator of the project and said that the new development “is expected to help unlock about three trillion cubic feet of additional gas resources” from shallow-water gas fields there to feed into the Tangguh’s 11.4MTPA LNG plant.

BP operates three liquefaction trains at Tangguh, the third of which began operation in 2023, exporting LNG mainly to Japan, China and South Korea. It took seven years for the third train to come on stream after final investment approval was granted. About 35 per cent of Indonesia’s gas production is expected to come from Tangguh in 2025.

First gas 2028

First gas production from the Ubadari field is expected to begin in 2028. The company says that the CCUS project will capture approximately 15 MTPA of CO2 in its first phase which will be injected back into Tangguh's reservoirs for enhanced gas recovery (EGR). Five development wells will be needed on the Ubadari field, and three EGR wells on Vorwata field, providing likely two years of work for a premium jack-up. Historically Valaris and its predecessor company Ensco has won BP’s Tangguh drilling work, but there will be a public tender for the rig, as always in Indonesia.

The Ubadari development will require two new unmanned offshore platforms, which Upstream reports will be installed in water depths of about 20 to 25 metres, and one platform in 40 metres of water depth for Vorwata EGR. These three structures will likely be fabricated in Batam or Karimun domestically.

The Ubadari development will require a 72-kilometre long, 24-inch diameter corrosion resistant alloy subsea pipeline from the new platform to the Tangguh LNG plant, whilst Vorwata will receive the highly acidic CO2 via pipeline from Tangguh’s existing onshore acid gas removal unit. Tendering will likely pitch Saipem against McDermott for the fabrication and installation.

Chevron’s carbon capture failure

"This project not only unlocks a fantastic gas resource," Murray Auchincloss of BP commented, "it also represents an Indonesian first through the use of CCUS to maximise gas recovery."

Inpex and Petronas’ plan of development for the Abadi LNG project also contains a CCUS plan.

Unfortunately, the record of CCUS in operation has been poor in Australia, where Chevron has struggled to achieve its carbon capture objective in the US$54 billion Gorgon LNG project on Barrow Island. The Financial Times reported last year that Chevron’s data showed that Gorgon’s CCS operation, which cost US$3 billion to build and is the largest operational CCUS system in the world, “stored only about a third of the total volume of CO2 it captured in the 12 months to June 2023, because of pressure management issues caused by excess water in its reservoirs.”

It is not clear why Australian performance in both CCUS and FLNG is so poor. Ten days ago, workers on the Prelude FLNG voted for industrial action, once again threatening a shutdown of the 3.6MTPA facility that has been plagued by technical issues since it first entered production in 2019.

Woodside wants to emulate BP after Chevron’s Gorgon horror

We wish BP and its partners better luck at reinjecting the CO2 from the Tangguh project back into the reservoir, rather than venting it into the atmosphere, as is common on many other LNG projects.

Woodside will be watching closely, as it has promised to use CCUS in its Browse Basin development of Brecknock, Calliance, and Torosa fields offshore Australia, 425 kilometres north of Broome in Western Australia. The proposed concept includes using two floating production storage and offloading (FPSO) facilities to extract hydrocarbons from the gas fields and send them via a pipeline approximately 900 kilometres long to the North West Shelf Project’s existing LNG plant infrastructure. Under this concept, the CO2 would be separated and re-injected into the Calliance reservoir from the FPSOs via up to seven injection wells.

Who knew that drilling wells for CO2 injection could be as lucrative for drillers as drilling wells for gas production?

Nine-Dash for Gas: Tuna no safe harbour for Harbour Energy

The next phase of Tangguh is not the only potential gas development in the pipeline in Indonesia to use existing infrastructure.

In late 2022, the Indonesian government made a landmark decision to approve Harbour Energy’s development plan for its US$3 billion Tuna oil and gas project in the Natuna Sea. Again, like all these gas projects in Indonesia, the natural resource has been known about for over a decade and has just sat undeveloped.

Tuna field was discovered in April 2014 and was successfully appraised via a two-well programme in 2021. During the drilling, Chinese vessels attempted to interfere, as the field lies within Beijing’s extremely controversial "nine-dash line" in the South China Sea.

Tuna field is a 100 million barrel of oil equivalent gas and condensate play, far distant from any existing Indonesian infrastructure for export, and too small for an FLNG project. Peak production was expected at 40,000 to 50,000 barrels of oil per day equivalent (boed), of which 55 per cent was expected to be gas and 45 per cent liquids to be produced and stored in a new floating unit.

Vietnam needs the Tuna gas

The genius of the development plan was that the gas would be exported to Vietnam via the nearby Nam Con Son gas pipeline, which was originally laid by BP in 2002. As with Tangguh, using existing infrastructure would make Tuna gas very low cost and would assist in meeting Vietnam’s soaring energy demand.

About 20 GW of power stations in Vietnam are coal-fired, generating around 40 per cent of Vietnam’s electricity, and about a quarter of the coal the country uses is imported. So, as in Europe, offshore gas would reduce emissions and diversify supply for Hanoi.

ExxonMobil go slow

We can look at ExxonMobil’s stranded deepwater gas discovery named Ca Voi Xanh off Vietnam later. This could power most of northern Vietnam for several decades, but has remained undeveloped since its discovery in 2011.

Vietnam, like Indonesia, has consistently struggled to get proven gas discoveries out of the ground. The development of Block B in the south of the country was finally given investment approval earlier this year by PetroVietnam and its partners including Mitsui and PTTEP of Thailand. First gas is estimated to be produced in 2026 and will eventually underpin four large gas-fired power plants in southern Vietnam. The field was discovered in 1997. Enough said! 

Project sanction doesn’t mean what you think in Tuna case

Unfortunately, Harbour has a Russian partner in the project, Zarubezhneft, so EU and UK sanctions have prevented Harbour as operator from undertaking further work on the project, including front end engineering and design (FEED), so long as state-owned Zarubezhneft remained joint venture partner on the licence.

So, Tuna goes back on ice.

Politics rules the gas market

It’s a reminder that often the problems holding back the dash for gas are political rather than geological. There’s plenty of gas out there, offshore. But getting commercially viable schemes agreed to sell it and satisfy governments and other stakeholders is hard.

But Russia’s foolish decision to invade Ukraine leaves an open goal for countries that want to develop new supplies from new fields, or to enhance production from existing LNG projects. Non-Russian gas projects should drive offshore drilling demand in coming years, even if the oil price wobbles and even if Donald Trump is back in the White House with a pro-fracking agenda.

For the same reasons that customers are wary of Russia as a supplier, many will also want to avoid dependence on the USA. Being at the mercy of a capricious nuclear power for your energy needs creates vulnerability, not resilience.

Background reading

Read Part One of this week’s offshore gas survey.

We first covered the global dash for gas in October here.

We looked at Indonesia’s efforts to “dethrone King Coal” last year with a study of the other gas projects underway there.