Hibiscus Petroleum embarks on first gas venture offshore Brunei
By Jeremy Beckman, London Editor
One of Malaysia’s fastest-growing independents, Hibiscus Petroleum, is expanding its presence in the region. The company recently completed a transaction giving it operatorship of the Maharaja Lela Jamulam (MLJ) gas field offshore Brunei Darussalam on the north coast of Borneo, close to its producing concessions offshore Sabah. Offshore spoke to managing director Dr. Kenneth Pereira about the rationale for this latest venture.
Offshore: Firstly, could you provide some background on the company?
Pereira: Hibiscus Petroleum is an E&P player listed on the Malaysian stock exchange with a market capitalization of around $400 million. The company is a specialist operator of mature offshore oil and gas fields in Southeast Asia and the North Sea, enhancing value of the assets through extending their economic lives. It currently produces around 100,000 boe/d (28,000 boe/d net).
Since inception, the company has adopted a strategy of arresting natural production decline and improving the performance of the acquired assets through applying ‘fit for purpose’ technical standards, smart capital allocation into viable projects and cost management. It employs around 1,000 professionals located across Malaysia, the UK, Vietnam and Brunei Darussalam, and works closely with local specialist engineering groups and service providers. The company’s operational and safety performance has led to 20 awards and includes the record for longest well drilled offshore Malaysia (7 km). Hibiscus’ partners include the national oil companies in Malaysia, Vietnam and Brunei, as well as Shell, Ithaca Energy, bp, Trafigura, PETCO, Ping Petroleum and 3D Energi.
Offshore: How did the opportunity to acquire operatorship of the MLJ gas field arise?
Pereira: Hibiscus continuously looks for opportunities in its areas of focus (Southeast Asia and the UK North Sea). TotalEnergies had been considering a divestment of its Brunei assets; after joining a competitive bidding exercise about in mid-2022, we decided to pursue this acquisition as it met many of our M&A criteria.
This is a quality gas asset producing to an onshore LNG facility. MLJ is located offshore Brunei Darussalam, within a prolific hydrocarbon-bearing region. We expect this acquisition to increase the percentage of gas in the group’s daily production from 36% to nearly 50%, helping the company move closer to its net zero 2050 goal. At present, the long-term production rights for MLJ continue to 2029, but this could be extended to 2039 with the agreement of the joint venture parties. Brunei Darussalam offers a favorable business environment with investor-friendly fiscal policies and proactive government support. In addition, the asset has a strong safety track record.
Offshore: Currently MLJ is said to account for 6% of Brunei Darussalam’s total gas production. How much of the field’s gas is allocated for domestic needs, and how much for LNG exports?
Pereira: From a gas supply perspective, all gas produced from the field is delivered to the Brunei LNG Plant. Although the field is mature, we are more interested in the absolute volume of recoverable reserves remaining and using this opportunity to act as a platform to grow our business organically in-country. With several of our previous field acquisitions, Hibiscus has increased the reserves basis.
Offshore: Under TotalEnergies’ stewardship, a third platform was added at the MLJ field in 2017 and an onshore compression project is underway at present. Does Hibiscus have plans for further new investments?
Pereira: The addition of the MLJ-3 platform has resulted in a significant production boost to the field. Going forward, the Low Pressure Compressor project is a prerequisite to reduce the MLJ pipeline system's turndown rate, which is essential in extending the field life until at least 2039. Currently there are two producing wells on the MLJ-3 platform—MLJ-3-03 and MLJ-3-05—both of which are 15,000-psi [1.034 bar] HP/HT wells. MLJ’s and Brunei’s deepest producing HP/HT well is at 5,517 m (18,100 ft) TVD/RT, with a maximum estimated wellhead pressure approaching the limits of 15,000 psi and temperatures exceeding 150 C [302 F] in a sour gas environment (CO2 and H2S).
The wells were successfully drilled in 2016/17 and remain two of the field’s major producers. MLJ-3-05 initially contributed up to 20% of MLJ’s production, and successful well interventions over the past few years have almost doubled the well rate so that it now contributes around 30% of the total field production. As a whole, the MLJ-3 platform provides 72% of MLJ’s overall production. The remaining 18% comes from the initial 11 development wells drilled on the first two platforms; the MLJ-1 platform also produces and processes two gas wells on behalf of a third party via a commercial agreement.
Potential investment in the future could take the form of appraisal drilling from one of the platforms and nearby exploration drilling. In addition, the partnership will consider investments to ensure well integrity.
Offshore: The MLJ field has multiple reservoir levels at the downthrown side of a major fault. Does this complicate drilling/recovery?
Pereira: Reservoirs or fields in the downthrown side of this major fault have been explored, with several discoveries in their individual panels in 2007 to 2013. These exploration wells encountered reservoir pressures up to the 15,000-psi drilling limit, drilling through major faults with ~100 m [328 ft] of displacement with the added challenges of wellbore stabilities and narrow mud weight windows. Drilling from the existing platforms through a major fault could always present issues due to unexpected pressure changes across faults and fault stabilities. In addition, if future wells were drilled through depleted reservoirs to target virgin reservoirs across the fault, very precise engineering would be required in terms of the mud and casing design, with managed pressure drilling needed to ensure getting to target safely.
It is noteworthy that at the time the ML-5 exploration well was drilled in 2010, its vertical depth of 5,664 m [18,582 ft] constituted the deepest for any well in Brunei Darussalam. It flowed 10 MMcf/d of gas and 220 bbl/d of condensate during a test from a limited zone at a depth of 5,350 m [17,552 ft]. This also was the deepest successful test anywhere in Southeast Asia at that time. ML-5 was the third positive exploration on the block since the campaign started in 2007, targeting the deep HP/HT horizons of the MLJ structure.
Offshore: How do commercial terms for E&P investors in Brunei compare with those of other countries in the Southeast Asia region?
Pereira: Most of the current production in Brunei is governed under a concession system where contractors pay royalty on gross production, and petroleum income tax on profit. What we can say is that the fiscal regime is simple, and the terms are competitive.
Offshore: Does Hibiscus plan to work exclusively at MLJ with established service groups in Brunei, or to bring in some of its own contractors?
Pereira: We do not intend to disrupt what already works; the team is highly competent and qualified to work the asset. We want to keep in-country value high. Right now, we are focused on stabilizing the asset and working with the team that manages the asset.
Offshore: How does Hibiscus view the global energy landscape, and what role will its Brunei assets play in meeting future energy demands?
Pereira: Hibiscus acknowledges the global shift toward lower-carbon energy sources driven by climate goals and regulatory pressures, with natural gas positioned as a key transition fuel. Demand for natural gas is rising as a cleaner alternative to other fossil fuels. That also aligns with Hibiscus' strategy of expanding its gas-weighted portfolio, helping to balance energy needs with achieving environmental goals.
The Block B MLJ field provides the company with direct exposure to the global LNG market, marking a significant expansion for Hibiscus beyond domestic gas markets and helping it to align with international energy needs. Throughout Southeast Asia, regional governments are prioritizing natural gas as cleaner fuel part of the energy mix, allowing domestic and regional suppliers to play a larger role in sustainable energy goals. At the same time, energy transition projects must be economically sound without the impact of long-term government subsidies.
The company is emerging as a significant player in the region, and we are close to achieving our 2026 net production target of between 35,000 and 50,000 boe/d. Our role in this space contributes to enhancing and stabilizing gas supply in the region. And by sustaining consistent production from a mature asset, we are supporting energy stability in the region.
