Natuna under pressure

Steve Hamlen profiles the East Natuna gas field offshore Indonesia.

Image from iStock.

The huge East Natuna gas field in Indonesia’s Natuna Sea is considered to be the largest undeveloped gas prospect offshore Asia.

However, the promise of huge gas reserves must contend with high carbon dioxide (CO2) content, political treadmills and the severe industry downturn. The development solution – subsea pipeline or an LNG facility – is also undecided, although a pipeline is the current favorite. Then, there is the massive budget of such an undertaking, estimated at anywhere from US$24-40 billion, depending on different sources.

Italy’s Agip discovered East Natuna (formerly Natuna D-Alpha) in 1973. The field has 222 Tcf (6.29 Tcm) estimated reserves, of which only 46 Tcf (1.30 Tcm) are recoverable due to the high CO2 content (72%), according to ExxonMobil. Removing the CO2 will require advanced technology and significant investment.

Since its discovery, the project has been delayed numerous times. The project’s partners [ExxonMobil, 35%), Indonesia’s Pertamina (operator, 35%), France’s Total (15%) and Thailand’s state player PTTEP (15%)], set a gas target of 2020 – but, this was before the price crash of mid-2014, and the aftermath of which makes this target look out of reach.

Oil price stumbling block

“I cannot yet confirm when operation will begin,” said IGN Wiratmaja Puja, Indonesia’s Ministry of Energy and Mineral Resources Director-General for Oil and Gas, last year. “We hope that it will start before 2030.” Giving an honest appraisal, Wiratmaja noted: “East Natuna is a special block, as it has big reserves and high CO2 content. With current technology and prices, the project is not economical.” He said that the project would only be economically developed when the price of oil reached more than a lofty $100/bbl. That level is some way off, even according to the most optimistic crude price forecasts.

Development options

The main problem is Natuna’s high CO2 content gas, which requires the development of advanced technology to separate and re-inject the CO2 back into the reservoir. This will make production costs much higher than more conventional gas reserves, let alone shale gas.

Development solutions have been evaluated over the years and the current favorite is a subsea pipeline concept, because it is the most cost-effective way to get gas to market, while an LNG project would hike the costs too much.

One upside of an LNG project is that it would make the gas easier to transport to numerous locations around Indonesia, as well as export further afield. However, although pipelines can only go to a fixed position, the planned and existing pipeline infrastructure in the region would allow the transport of East Natuna gas to Indonesia, Malaysia, Thailand and Singapore.

If the pipeline option is followed, the East Natuna gas field could start producing at 1 Bcf/d (28.33 MMcm/d), with peak output to reach 4 Bcf/d (113.3 MMcm/d), ExxonMobil said. Peak production could last for at least 20 years before it started to decline.

The current estimate for Pertamina to build pipelines for the East Natuna development, including linking the pipelines into the Southeast Asia regional network for export, is about $24 billion, said Infield Systems, although other estimates from industry analysts suggest this will cost around $40 billion.

This is a wide gap in estimates, but to give some clarity, capital expenditure on the East Natuna project itself, up to 2022, has been estimated at around $11.6 billion by Infield Systems.

And, then, there are the costs of CO2 removal, on which the Global CCS Institute said: “The addition of CO2 transport and injection facilities to the development of the East Natuna discovery would require additional capital costs of about $5.975 billion (in 2010 dollars).

“The extra annual operating costs would be approximately $180 million/yr and the additional decommissioning costs would be about $1.470 billion incurred after a CO2 injection period of 75 years.”


The East Natuna structure is a middle-to-late Miocene platform reef carbonate and lies around 200km northeast of Natuna Island in the East Natuna Basin.

The geological composition of East Natuna is, “a large structural stratigraphic hydrocarbon trap and is unique in areal extent and reservoir thickness among the various carbonate traps, which are present in many Southeast Asian basins,” said geoscience firm PGS, which completed the acquisition of a high definition MC3D survey on the field area in 2010.

“The data from the seismic survey will enable companies to make detailed reserve assessments, as well as identify the main depositional bodies and producing intervals within the carbonate reservoirs,” PGS adds.

Learning process

Pertamina has said the ideal form of partnership on East Natuna, with ExxonMobil, Total and PTTEP, would be like that between Norway’s Statoil and supermajor BP, which helped Statoil gain knowledge and expertise in deepwater operations.

Pertamina is hoping its partnership for East Natuna will help it gain knowledge and skills that it will be able to apply on other projects in Indonesia, such as the Mahakam Block.

But, fruitful relationships haven’t been forthcoming to date. In 2006, Indonesia revoked the East Natuna license from ExxonMobil on the grounds that the US player failed to provide a feasibility study for the proposed development within the time frame of rules set out by a production sharing contract, which was awarded in 1985 and amended in 1995.

Following numerous issues with red tape and lengthy talks with various government departments – as well as upstream watchdog BP Migas (since disbanded and relaunched as SKK Migas) – over the years, the latest partnership still includes ExxonMobil.

The partners remain keen to make progress on this troubled project despite the long list of problems that will surely provide further roadblocks along the way. Given the obstacles to overcome, 2030 may come along all too quickly.

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