King of the Kutei basin: Eni considers third offshore production hub in Indonesia

Italian energy giant Eni is already considering a third production hub in the Kutei basin offshore East Kalimantan, Indonesia, where it has identified exploration prospects with unrisked reserves potential of 30 trillion cubic feet of gas.

This possible future hub could feature an even larger capacity floating production unit than the one currently out to tender to exploit the operator’s Geng North giant gas discovery and other fields in the north of the basin.

This North Kutei FPU has touted nameplate capacity of around 1.2 billion cubic feet per day of gas plus significant amounts of liquids.

“The discovery of Geng North was a play opener. When we assessed the basin, we found [identified] 30 Tcf of reserves,” Guido Brusco, Eni's chief operating officer natural resources, told Upstream.

“If we assume a very successful [future] exploration campaign, if you assume a probability of success of 30% — which is the average of the industry — it’s 10 Tcf [of gas], [then the new hub facility] would be an FPU carbon copy of [North Kutei].

“If you assume a 60% [success rate], it will be another, bigger size,” Brusco told Upstream in an exclusive interview on the sidelines of Gastech 2024.

Eni over the next four years intends to test a number of these Kutei basin prospects, with the initial two exploration wells being drilled from early 2025.

These upcoming wildcats will be targeting similar geology to Eni’s 2023 play-opening multitrillion cubic feet Geng North liquids-rich gas discovery.

The gas in the northern part of the Kutei basin is typically rich gas while dry gas is found in the south of the basin.

Tenders launched

Eni recently launched tenders for the key facilities and materials to exploit Geng North and some of the Indonesia Deepwater Development (IDD) fields that it acquired from US supermajor Chevron, which will comprise the Kutei North hub development.

This project will centre on a newbuild FPU equipped with condensate storage. The “pretty sizeable” floater will be designed with capacity of around 1.2 Bcfd of gas and 80,000 barrels per day of condensate, with the gas to be utilised as feedstock at the Bontang LNG plant that has spare capacity.

The offshore hub project is expected to be operational in 36 to 40 months.

Brusco explained just how rich the gas is in the north of the Kutei basin. One well that Eni tested can produce up to 150 million cubic feet per day of gas plus 7000 to 8000 bpd of condensate.

“That’s really high,” he says of the flow rates.

“You may see it as a gas well, very liquids rich; or an oil well with a high gas oil ratio.”

For the initial North Kutei FPU, the spoils are expected to be shared within Indonesia and overseas yards.

Eni’s compatriot Saipem and McDermott of the US have fabrication facilities in Indonesia, on the islands of Karimun and Batam respectively.

Industry sources have suggested Saipem as the likely winner of at least the FPU’s integration, not least because the contractor delivered the Jangkrik facility for Eni, so there would be synergies.

“They have a lot of unused capacity at the moment. So, seeing our project [is] very close to FID, we have made already contact with this yard. We have already reserved some slots for at least the key component of the project,” said Brusco.

He added that while the smaller modules for the North Kutei FPU could be fabricated anywhere in the world, the integration would likely be performed in Indonesia — not least as this would help to meet local content requirements.

McDermott and Saipem — both having in-country advantage — are understood to be in the fray as is potentially Malaysia Marine and Heavy Engineering and possibly also a yard in China.

“The market can decide… but you can meet the local content requirements if some of the work’s done in-country,” said Brusco.

Eni will likely award the major contracts for its North Kutei hub project in 2025.

Meanwhile, the company’s Jangkrik FPU in the southern Kutei basin, which started up in 2017, is currently producing 750 MMcfd of gas with the volumes also piped to the Bontang LNG project in East Kalimantan province for liquefaction. Tying back other of the IDD fields to the Jangkrik floater means that plateau production from this facility can be extended by 10 to 15 years, noted Brusco.

These tie-ins are expected to take 24 months to come online. The Jangkrik FPU will not need to be upgraded or rejuvenated to handle these volumes of backfill gas, so the facility can remain on location as it has a 25-year design life.

Pivoting to the east

The Italian company is very bullish about its geographic pivot eastwards from its earlier key focus area of Africa, in particular to Indonesia where it is becoming a significant player in the republic’s upstream and LNG sectors.

Brusco said that not only would its volumes produced at Bontang be sitting in a premium market (North Asia), but they would also be price competitive given the development cost of between $10 and $15 per barrel of oil equivalent.

“The [Bontang liquefaction] plant is already there. We don't need to build an LNG plant. That's it in a very nutshell,” he told Upstream.

“An LNG plant of that size would cost $5 billion to $6 billion, so that cost component removed from a project clearly would make it very much cost competitive.”

The North Kutei hub project will require a carbon steel pipeline to deliver the feed gas “but that wouldn’t cost a fortune, it’s $100 million, $200 million”, he noted.

The operator has no obligation to sell any of the condensate it produces within Indonesia but, if it did so, it would not be at a subsidised price. There is a commitment to sell some of the produced gas in the domestic market, but that price is not far from market price.

“I mean, it’s a little discounted, but not that far,” said Brusco.

Expanding LNG portfolio

Eni markets the volumes of LNG produced at Bontang from its feed gas, and when the North Kutei hub project comes into operation it will account for some 6 million tonnes per annum (approximately 25%) of the facility’s 22.5 million tpa nameplate capacity.

The company today has a contracted quantity of 13 million tpa of LNG — up from 9 million tpa last year — and its plan is to hit 18 million tpa in 2027.

Within its global LNG portfolio, Eni’s marketing strategy varies on a project-by-project basis depending on the geography, the quality of the LNG and its vicinity to a premium market.

With all factors considered, the operator might allocate 50% to 70% of LNG from a project to long-term contracts with the remaining cargoes being sold in the spot market.

“It’s project specific, there is no one rule or guideline in the company,” said Brusco.