A powerhouse regional oil and gas producer, Brunei Darussalam has benefitted significantly from a long history of production in partnership with international oil companies. Hydrocarbons continue to dominate its economy today, accounting for the majority of government revenues, GDP and exports. The sector is facing a host of concurrent challenges – production at Brunei Darussalam’s mature fields has been in decline for a decade, while oil and gas prices have declined rapidly since mid-2014 – putting a significant strain on expenditure, investment and economic growth. Although the near-term forecast for energy sector growth is subdued, there have been a number of positive developments in recent years which will support long-term expansion. Ongoing upgrades and investment in existing production, particularly in the Champion and Maharaja Lela fields has bolstered reserve recovery, while the construction of an integrated refinery and petrochemicals complex will further underpin the sector’s diversification and revenue growth. The government’s 2014 “Energy White Paper” aims to attract billions of new investment, in renewable energy projects as well as hydrocarbons production.
Brunei Darussalam’s history of oil and gas production dates back nearly 90 years, with commercial production first commencing in the 1920s at the onshore Seria field. With an estimated 1.1bn barrels of proven reserves as of January 2016, Brunei Darussalam holds the fourth-largest oil reserves in South-east Asia, and stands as one of the largest oil and gas exporters regionally, benefitting from its deep history of exploration and production in partnership with international oil companies.
The Energy and Industry Department of the Prime Minister’s Office (EIDPMO) is the primary government body tasked with overseeing the energy sector. There are 10 divisions and units operating under the EIDPMO, including upstream and downstream businesses, sustainable energy, power and generation, local business development and policy and international affairs. The Brunei National Petroleum Company (PetroleumBRUNEI) is the national oil company, established in January 2002 to explore and produce from various blocks, although the company’s focus has shifted in line with the government’s long-term energy strategy, encapsulated in the “Energy White Paper”, which emphasises investment in international oil production. As a result, PetroleumBRUNEI is turning its attention to international investments and operations, with the target of reaching 100,000 barrels of oil equivalent per day (boepd) from foreign projects by 2035.
In September 2014 PetroleumBRUNEI won a tender for a small onshore block, EP-1, in the Kyaukkyi-Mindon valley in Myanmar, representing an important first step into international oil operations. The company also holds a 3% stake in the Petronas-led, $36bn Pacific Northwest LNG project, which would produce 12m tonnes per annum (tpa) of natural gas from British Columbia, Canada. However, Canadian officials announced they were delaying a final decision on the project in March 2016, leaving its future development in doubt.
In 1929 Brunei Darussalam entered into what has become its longest-standing joint energy venture with Royal Dutch Shell subsidiary British Malayan Petroleum Company. This critical partnership was a forerunner to the present-day joint venture between the Sultanate and Shell, Brunei Shell Petroleum (BSP), as well as various related firms – Brunei LNG (BLNG), Brunei Shell Marketing (BSM), Brunei Shell Tankers (BST) and Brunei Gas Carriers (BGC). These companies collectively form the Brunei Shell Joint Venture. BSP remains the largest and most significant player in the oil and gas industry, having been established in 1957 and operating today as a 50:50 joint venture between Shell and the government. BSP accounts for 90% of the Sultanate’s oil and gas output, and made its first offshore discovery in the huge South West Ampa Field in 1963. Brunei LNG was established in 1972 as the Sultanate sought to capitalise on growing demand in industrialising Japan. The government and Shell partnered with Mitsubishi to establish Asia’s first liquefied natural gas (LNG) plant at Lumut, east of the onshore Seria field, which is Brunei Darussalam’s oldest oilfield. The plant has since undergone two upgrades to reach a total capacity of 7.2m tpa, and Japan is Brunei Darussalam’s largest energy export market today, accounting for over two-thirds of LNG export revenues in 2014. In 2001 Shell acquired New Zealand’s Fletcher Challenge Energy and established Shell Deepwater Borneo, owned 100% by Shell and holding offshore licences in Block A, Block B, Block N, Block Q and CA2.
French oil firm Total, then operating as ELF Aquitaine, began exploration activities in 1986, later discovering a commercial field, Maharaja Lela/Jamalulalam, in 1990. The company formed a joint venture with PetroleumBRUNEI to become Total E&P Borneo, and today Total holds a 37.5% stake in the Maharaja Lela South (MLS) project, while Shell holds 35% and PetroleumBRUNEI 27.5%. Total discovered significant oil and gas deposits in the field in 2010, after drilling to 5664 metres, setting a new national record. Following years of rig and platform construction, the field’s third well commenced commercial deepwater operations in August 2015. The project is expected to play a significant role in meeting the Sultanate’s long-term energy targets, despite facing near-term market volatility (see analysis). Total also holds a 54% stake in the CA1 production block, previously known as Brunei Block J. The Sultanate has also actively pursued production-sharing agreements with Malaysia, following a settlement between the two in 2010, which allowed Brunei Darussalam to explore untapped and previously disputed deep-water areas in blocks CA1 and CA2, located in the Baram Delta. In the same year, Malaysia’s Petronas and PetroleumBRUNEI signed a 40-year deal to jointly explore the two blocks. In 2013 PetroleumBRUNEI and Petronas signed another series of agreements to undertake joint development of deepwater offshore oil and gas fields, and in August 2015 Malaysian prime minister Najib Razak said that the two countries are close to reaching a joint oil and gas exploration agreement for the overlapping blocks, during a visit to Bandar Seri Begawan.
Domestic Production Targets
The 2015 BP “Statistical Review of World Energy” states that Brunei Darussalam’s reserve-to-production ratio – meaning how long proved reserves would last if no new supply was found and production continued at the present rate – stands at 23.8 years. However, Brunei Darussalam’s mature onshore and shallow offshore fields have seen production decline significantly over the last decade, leading the government to set ambitious production targets emphasising deployment of enhanced oil recovery (EOR) techniques, new drilling, and development of smaller fields and international investments.
The government’s “Energy White Paper” targets 6% annual growth in real terms to boost energy’s economic contribution from BN$10bn ($7.1bn) in 2010 to BN$42bn ($30bn) in 2035, in addition to ambitious new production targets, with the government targeting the addition of 3.5bn barrels of new reserves by 2035, and boosting production from an estimated 372,000 boepd in 2013 to 430,000 boepd in 2017 and 650,000 boepd by 2035.
Other targets include attracting between $70bn and $80bn of new foreign investment in the energy sector, boosting the amount of goods and services provided by local companies to the energy sector from $400m in 2010 to $7bn in 2035, increasing employment in the sector from 20,000 in 2010 to 50,000 in 2035 and reaching 50% local content for goods and services to the energy sector by 2017, which will rise to 80% by 2035. This presents considerable opportunities for private players to expand, particularly in the renewable energy segment.
“An experienced workforce with the right skill set is crucial within the oil and gas services industry. It can take up to five years to train a new worker and then companies need to make sure to retain quality human resources,” Shahrurrizam bin Tua, managing director at SC Oilfields & Logistic, told OBG.
After reaching a peak of 220,000 barrels per day (bpd) in 2006, production of petroleum and other liquids in Brunei Darussalam has since declined by nearly half, to hit an estimated 125,000 bpd in 2015, a moderate increase over 2014’s 124,000 bpd, according to the US Energy Information Agency (EIA). Despite this, Brunei Darussalam remains the largest net exporter of total petroleum liquids in the Asia-Pacific region as a result of minimal domestic consumption, with net exports of total liquids standing at 110,000 bpd in 2015, a 3.8% increase over the 106,000 bpd recorded in 2014. The EIA reported that the majority of oil exports was crude oil shipped to key Asian partners including Japan, South Korea and China.
The “Brunei Darussalam Statistical Yearbook 2014”, meanwhile, reported that average crude oil and condensate production in 2014 stood at 126,450 bpd, a 6.4% decline from 2013’s 135,160 bpd. According to the yearbook, this was due to a high deferment rate of 33.2%, which was related to asset integrity issues, maintenance and operational issues within the West Fairley-4, Champion 7 Complex A and Darat Tank Group 28 facilities.
The yearbook also reported higher levels of crude exports in 2014, noting that oil exports declined by 7% to hit 117,570 bpd on average, compared to 126,350 bpd in 2013. Brunei Darussalam’s major oil export destinations were ASEAN countries, which comprised 35.9% of the total export market, followed by India (21.2%), Australia (19%), South Korea (12.6%), New Zealand (7.8%), and Japan (3.4%). The yearbook reported that 98.5% of oil and condensate exports were sold under term sales, and the remainder under spot sales.
Although the statistical yearbook reported that the weighted average export price of crude oil and condensates was $104.4 per barrel in 2014, which is a comparatively moderate 9.2% decline from 2013’s $115.03 per barrel, oil and gas prices dropped sharply in mid-2014, and continued to decline throughout 2015 and into 2016, dropping to $30 per barrel in January 2016 before recovering to roughly $40 per barrel at the end of March. Oil and gas accounted for 92.2% of total export revenues in December 2015, and make up 60% of GDP in Brunei Darussalam, making the Sultanate extremely vulnerable to energy price volatility. Combined with ongoing maintenance and declining production at Brunei Darussalam’s existing, mature fields, this has driven the sector to embrace both downstream diversification and new production, employing EOR techniques in the Champion field through the Champion Water Flood Project, as well as undertaking new deepwater drilling for the MLS project.
According to the statistical yearbook, average natural gas production fell by 2.3% in 2014 to 231,710 boepd, compared to 237,240 boepd in 2013. The department attributes this to ongoing maintenance work as a result of significant electrical power failures in the Champion offshore field’s Champion Complex 7A, which caused production to halt for 40 days. Gas from offshore wells comprised 92.5% of total production in 2014, or 214,420 boepd, compared to 17,290 boepd of onshore production. Roughly 10% of produced natural gas is consumed domestically, and accounts for the vast majority of electricity generation in the Sultanate, while the rest is exported as LNG after processing at Lumut. Average LNG exports stood at 886.4bn British thermal units (Btu) per day, a 9.7% decline from 2013. Japan was Brunei Darussalam’s largest LNG customer in 2014, accounting for 74% of LNG export revenues, followed by South Korea (11.5%), Taiwan (10%), Malaysia (3.5%) and China (1%). Average export prices rose by 1.4% in 2014, according to the statistical yearbook, although spot prices in Japan fell by nearly 60% between April 2014 and December 2015, from $18.30 to $7.50 per million Btu, in line with broader international energy trends. Having signed two long-term LNG agreements in 2013, Brunei Darussalam is better insulated to withstand near-term gas market shocks, although the rising prevalence of short-term spot contracts, coupled with increased regional competition from the US and Australia, could be cause for concern in the nearer-term (see analysis.)
Oil and gas production is concentrated in shallow, offshore and ageing fields which have been extensively explored over the previous 80 years. The largest and most mature of these include the onshore Seria field, as well as the Southwest Ampa and Champion fields, which are located in the offshore Baram Delta. More recent developments have tended to concentrate on fields discovered years earlier, but that were too difficult to develop – the Champion West satellite field, for example, was discovered in 1972 but did not begin commercial production until 2005, which enabled 2006’s peak oil production. Other recent discoveries of note include the Mampak field, which was found in 1997 and began production in 2009, Selangkir, found in 1995 and producing from 2011, and Danau-Bubut, discovered in 1969, with commercial production only commencing in 2012. Although these discoveries have not been enough to offset declines in older fields, recent investment in Champion’s Maharaja Lela field should keep the government on track to meeting its long-term production targets.
Brunei Darussalam’s oldest oilfield, the Seria onshore field, was the first commercial oil discovery in the Sultanate. Spanning 13 km along a 2.5-km strip on Brunei Darussalam’s western coastline, the field was discovered in 1929, and reached its milestone one billionth barrel in 1991. Situated on an area of strong surface oil and gas seeps first noticed by explorers in 1926, development of Seria’s shallow, heavy oil proceeded rapidly after its discovery, with production reaching 1590 cu metres per day from 77 wells by 1936. On discovery of deeper, lighter oil in the field, production further rose to 2700 cu metres per day from 158 wells by the outbreak of the Second World War. Production peaked at 18,780 cu metres per day in 1956, with 500 wells drilled in the field by 1958, although it began to decline rapidly in the 1960s. Despite the launch of several EOR projects in the 1960s, production fell below 4770 cu metres per day by 1977, before recovering to 5530 cu in 1985, again as a result of EOR deployment, including water injection into heavy oil reservoirs.
As of 1996 a total of 774 wells had been drilled in the field, of which 307 were producing, and it retains high potential for future development, with BSP reporting that the field’s ultimate recoverable oil is estimated at 175m cu metres. Although Brunei Darussalam does not publish production figures for specific oilfields, BSP announced in 2010 that production at Seria had doubled since 2010, with nearly 900 onshore oil wells having been drilled.
The company also announced that it planned to employ EOR at the field to maintain production levels. According to the BSP website, production at Seria currently stands at 28,000 bpd.
Offshore Oil & Gas
BSP made its first offshore discovery in 1963 with the giant South West Ampa field, which is located 25 km west of Seria, in water depths of between 10 and 40 metres. The field is divided into three major hydrocarbons-bearing areas: the main field, the southern area and the 21 area. Oil production in the main field commenced in 1965 and reached 9500 cu metres per day between 1968 and 1970, peaking at 20,000 cu metres per day by 1973, with LNG production commencing in the same year. According to BSP, 279 wells had been drilled in the field, of which 161 were producing, as of 1996. Ultimate recovery for the field is estimated at 128m cu metres of oil, 35m cu metres of condensate and 345,109 cu metres of gas. Although most of its oil reserves have been produced, it remains the largest field in operation in Brunei Darussalam, and is expected to remain a significant source of natural gas for many years, with BSP reporting that the field contains more than half of its total gas reserves and gas production, and accounts for 60% of the company’s total production. There are currently 56 gas wells which pipe gas through a 39-km pipeline to the Brunei LNG plant in Lumut. The field also holds 164 oil-producing wells.
The Champion offshore field was discovered in 1970, and is located 40 km north of Bandar Seri Begawan, in water depths ranging from 10 to 45 metres. The first gas platform on the field was completed in 1972, the same year as Brunei LNG began operating Asia’s first large-scale LNG plant in Lumut, followed by eight appraisal wells between 1975 and 1976. Construction of the centralised field facilities within the Champion-7 block began in 1980 and finished in 1983, with BSP reporting that 282 wells had been drilled as of 1996, of which 118 were producing. Average production rates stood at 10,000 cu metres per day of liquids and 1.2m cu metres per day of gas in 1995, with the field requiring 7000 cu metres per day of water injections to maintain pressure in a number of reservoirs. Today the field is a prolific producer with high future potential, with BSP reporting that it holds 40% of known reserves, and produces roughly 100,000 bpd at 260 wells drilled across 40 platforms.
Champion Water Flood
In 2009 BSP officials unveiled the Champion Water Flood project, an ambitious drilling project aimed at maximising production from the Champion field, which at that point has produced some 686m barrels of oil, although this represented just 20% of total natural resources in the reservoir. The project aimed to restore lost pressure in the field, which accounted for 57% of BSP’s oil production and over 30% of natural gas production as of 2013.
To accomplish this goal, authorities announced plans to introduce pioneering techniques and technologies, including a chemical flooding technique employing alkaline surfactant polymer and nontoxic chemicals to flood the complex, technically challenging field, making previously inaccessible petroleum reserves accessible to drilling. BSP said that it planned to drill over 130 new wells, in addition to constructing nine new offshore structures.
The first oil from the project was produced in 2012 from the A1 phase, which involved drilling 20 new wells, including water injection wells. The A2 phase kicked off in May 2013, and involves drilling 22 new water injection and producing wells, in addition to platform upgrades, the installation of a new water injection pipeline, and two sub-sea composite cables which provide power and fibre-optic connectivity. Drilling platform CDPD 37 was successfully upgraded for the launch of phase A2, with BSP officials announcing plans to demolish and reconstruct a number of offshore platforms in the field by 2015. In April 2013 Damit Worley Parsons, which is providing engineering and project management services, said that the company was planning to tender contracts for 12 new platforms to be delivered in two phases of six units each, and in August 2013 China’s Offshore Oil Engineering Company won a contract for six new platforms.
The $1.4bn MLS project, involving deepwater exploration of Brunei Darussalam’s Block B, presents perhaps the most viable opportunity to meet the Sultanate’s long-term production targets, and stands as a rare example of significant new drilling activity in the region in 2015. Drilling commenced after the launch of a 4200-tonne, $100m deepwater well, constructed by Vietnam’s PTSC Mechanical and Construction Company, in August 2015. The project was developed in three parts, including the fabrication of the platform and topsides, installation and laying of 85 km of infield pipeline, and modifications to the existing Lumut processing plant which will enable it to handle higher levels of hydrogen sulphide in the gas. Although an investment of this size under current market conditions could be seen as a risk, Total stakeholders argue the project has found some silver lining as a result of prevailing oil market volatility. “In the new economic environment, rationalising our spending and bringing costs down as much as possible is absolutely essential to the sustainability of our business. For our MLS project, we fortunately had not awarded the contracts for the development drilling phase before the downturn so that we could benefit from the readjustment of the market conditions. We were able to negotiate better rates for the rig as well as for the drilling services than anticipated when the project was launched. Indeed, the project final investment decision was before the downturn,” Total E&P Borneo’s country director, Yves Grosjean, told OBG.
The new well will significantly augment production at the MLS project’s existing wells, which came on-line in 1998 and 1999, extending the field’s lifespan by 25 years by utilising advanced drilling technology designed for the challenging technical conditions and 5-km drill depths, according to Grosjean. This is in line with overall efforts to modernise the sector. In August 2015 Brunei Darussalam announced the launch of a third well, which was built in Vietnam by PTSC Mechanical and Construction Company at a cost of $100m. The well is expected to bring existing production in the Maharaja field from between 32,000 and 34,000 boepd to between 42,000 and 44,000 boepd.
The most significant downstream project under development at present is the $4.3bn Hengyi Refinery, which is 70% owned by Chinese firm Zhejiang Hengyi Petrochemicals and 30% owned by the government of Brunei Darussalam. The refinery is one of the world’s largest overseas projects under development by a private Chinese company, and represents a crucial next step for Brunei Darussalam’s energy industry, as it will enable production of value-added petrochemicals products and aromatics – used in the production of polymers, plastics, resins, polyester and nylon – in addition to creating up to 1200 new jobs. The project was conceived in 2011 as part of the Pulau Muara Besar industrial island project, similar to Singapore’s Jurong Island, which has become a critical pillar of Singapore’s energy and chemicals industry, housing over 100 global petroleum firms.
The plant is set to play the role of anchor tenant in a 955-ha industrial zone which is currently in the midst of major infrastructure upgrades, including dredging for a deepwater container terminal, construction of an export processing zone, and the Temburong bridge, one of the largest infrastructure projects under development in Brunei Darussalam (see Construction chapter). In 2012 officials reached a land leasing agreement with the Brunei Economic Development Board, followed by official approval for the project in February 2013.
Spanning an area of 260 ha, the Hengyi Refinery is being developed in two phases. The first phase, which was originally scheduled for completion in 2015, but has since been extended to late 2017 or early 2018, involves construction of a refinery which will produce 135,000 bpd of crude oil and condensates, 1.5m tonnes per annum (tpa) of diesel, 400,000 tpa of gasoline, 1m tpa of jet fuel, 1.5m tpa of naphtha cracker, 1.5m tpa of paraxylene and 500,000 tpa of benzene. Phase two of the project includes the expansion of the refinery into olefin production units capable of producing 1m tpa of paraxylene and 2m tpa of monoethylene glycol. Construction works include installation of an atmospheric and vacuum distillation unit with 8m tpa of capacity, a hydrocracking unit with 2.2m tpa of capacity, an aromatic complex unit with 1.5m tpa capacity, a diesel hydrogenation unit with 1.5m tpa and a kerosene hydrogenation unit with 1m tpa capacity.
Oil and gas technology supplier, Honeywell UOP, was awarded a major contract to provide aromatics production technology for use in the plant, including a continuous catalyst regeneration platforming unit and a UOP Parex unit, each adding 3.3m tpa and 1.5m tpa of capacity, respectively.
Authorities initially planned to use crude oil, one third of which would be sourced from Brunei Darussalam, as feedstock for the factory, with BSP, BSM and Zhejiang Hengyi planning to supply 2.8m tpa of crude oil for the project, in addition to acting as purchaser for refinery products to be sold on the international market, under a 15-year non-binding memorandum of understanding signed between the three. Hengyi was planning to secure the remaining 70% of crude feedstock needed, of which 30% will be sourced from the spot market and 40% from term agreements.
Brunei Darussalam will then offtake 20% of total petroleum products from the refinery, including gasoline, jet fuel and gas oil, with the majority of heavy grade naphtha to be used in the paraxylene plant, and some in the gasoline pool.
Delays & Challenges
The plant’s first phase, originally scheduled for completion in 2015, was pushed back by at least two years in October 2014 as designs and planned on-site facilities evolved, with authorities now hoping to see an opening in late 2017 or early 2018. P C Huang, vice-president and country director of Hengyi Industries, told OBG that delays in obtaining the necessary electricity and water utilities (see analysis), as well as the addition of a coking plant, which will augment the plant’s crude fuel supply, were the primary reasons for the delay in construction.
Moving forward, Huang said the project will face further challenges in sourcing local workers for the labour-intensive project, meeting the shipping demands of the high-output refinery using port facilities which are limited at present, and developing a robust local trading system, as Brunei Darussalam’s banking sector is not ready to support international petrochemicals trading.
However, the economic benefits on offer are significant. In 2015 the Asian Development Bank forecast that on completion, the Hengyi complex will add an additional $2bn to the Bruneian economy, and boost GDP growth by 2% once fully operational, further augmenting economic diversification efforts and providing significant opportunities to capitalise on ongoing ASEAN industrialisation. The IMF, meanwhile, forecasts that Brunei Darussalam’s energy sector GDP growth will jump from 2.9% in 2018 to 12.5% in 2019, due in large part to Hengyi coming on-line, in addition to an anticipated recovery in oil prices.
Energy diversification will be further augmented by an ambitious renewable development programme, as envisioned by the 2014 “Energy White Paper”, which targets reaching 124 GWh per year of renewable power generation by 2017, and 954 GWh by 2035. The “Energy White Paper” also targets reducing energy intensity, which is measured by energy consumption per unit of GDP by 45%, from a base of 390 tonnes of oil equivalent per $1m of GDP in 2005 to 215 tonnes of oil equivalent per $1m of GDP by 2035, which will promote sustainable energy projects, and preparing for rising demand for petrochemicals production from the Hengyi project. Renewable development remains limited to a solar power plant, Tenaga Suria, producing roughly 1.34 GWh of power per year. Yet many players see the segment is in the process of planned expansion. “Capitalising on natural assets remain a challenge to many countries, but by building the right infrastructure, renewable energies such as solar energy are real solutions in order to decarbonise the electrical grid,” Norman Kurz, general manager, Berakas Power Management Company (BPMC), told OBG.
Retrofitting of waste heat recovery systems is also a viable alternative to increase efficiency. The BPMC is finalising the installation of an OR egen waste-heat recovery system on four of their 14 GE 2500 gas turbines. This project is due for completion in the fourth quarter of 2016 and will add an additional 14-MW net to BPMC’s generation capacity, increasing the efficiency of the units in question by approximately 45%. This plant is the second such plant in the world and the first in the Asia. There is potential to generate a further 42 MWs if additional development phases are embarked upon.
Private Sector Participation
The “Energy White Paper” also envisions the government taking a lead role in identifying land for utility-scale solar projects, as well as developing a waste-to-energy project using municipal solid waste. Private sector partnerships will be critical for the renewables programme, and on this front Brunei Darussalam has already made good progress, signing a memorandum of understanding with the Export-Import Bank of the US in May 2014 to explore regional trade and renewable energy business opportunities, as well as a potential $1bn loan to finance exports in support of planned new projects. The private sector is also showing some interest, and in March 2016 Taiwan’s KD Holding announced that the company is interested in forming a public-private partnership for a renewable energy project, having already developed biofuel and photovoltaic solar power plants in Taiwan, China and the US.
Although the near-term forecast will likely see both public and private stakeholders continue to struggle with depressed oil and gas prices in a competitive market, new developments will keep long-term development on track. Forays into international oil production, new deepwater drilling projects, petrochemicals expansion and an emphasis on renewable development will keep the industry at the forefront of economic growth.
As regional cooperation, power grid upgrades and renewable energy projects continue to move forward, the energy sector is well positioned to capitalise on rising demand in South-east Asia, lending a more optimistic long-term outlook to growth.
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