Like all traditional oil and gas producers, Brunei Darussalam is running an uphill race against time. The giant fields that have been the country’s mainstay since the 1970s or earlier are in decline, and the remaining undeveloped resources are increasingly difficult to reach. They are deeper and in smaller, more scattered reservoirs.
In order to stay ahead, the Sultanate must ensure that conditions are welcoming enough for investors for them to utilise the latest technologies in their exploration and development efforts, while at the same time ensuring that the country receives its fair share of the output. And no matter how well the government maintains that delicate balance, results will depend on the luck of what ancient deposits lie under its sea and soil.
A Tough Climb
The hill has been especially steep for Brunei Darussalam since its combined oil and gas output peaked in 2006 at around 450,000 barrels of oil equivalent per day (boepd), according to the “Energy White Paper”, a major policy document released by the Energy Department at the Prime Minister’s Office (EDPMO) in March 2014. Since then output has declined to 372,000 boepd in 2013, as the introduction of new wells has failed to keep up with the decline seen at older ones.
Output in 2013 also took a temporary hit as a result of renovation of ageing production infrastructure. According to the EDPMO, the drop in 2013 was not due to the fields, but to the infrastructure, platforms and pipelines, which are ageing. The problem has been a major issue on the production side, as the government’s emphasis on safety means anything that has been identified as being at all unsafe must be shut down and replaced.
A 50: 50 joint venture between Royal Dutch Shell and the government, Brunei Shell Petroleum (BSP) is working through those issues, and there is much optimism that the decline will be reversed. The EDPMO paper set an ambitious target for recovery of 430,000 boepd by 2017 and a further rise to 650,000 boepd by 2035. And it would not be the first time the country’s oil and gas industry has made a dramatic comeback. Combined oil and gas output initially peaked in 1979-80, also at around 450,000 boepd, but then output fell back to around 325,000 boepd in the late 1980s before starting a new growth trend that led to the 2006 peak.
Keeping Up
While output has fallen, the EDPMO reports a significant improvement in Brunei Darussalam’s reserve replacement ratio (RRR) in the past five years. The country rarely divulges any numbers on its oil and gas reserves, which the Sultanate regards as a sensitive trade secret.
However, in its “Energy White Paper”, the EDPMO revealed, “The reserve replacement ratio from the two major producing concessionaires has been in the range of 0.3 to 0.7 over the last decade. Recent RRR has been higher; above 1 in the last five years. The major concessionaires have developed plans to ensure that the success of the past few years is sustained for the rest of this decade, with significant exploration programmes in place.” Plans currently under way, along with production in offshore blocks, are expected to provide 3.5bn barrels of oil equivalent in cumulative reserves by 2035.
The white paper also details three initiatives that the government plans to focus on to ensure long-term sustainability in upstream production. The first, exploring unlicensed acreage, will entail the “review of existing energy legislation” to better facilitate exploration activities. The second involves the development of new fields through “accelerating the study of maturing fields to enable booking of new reserves” and “developing unconnected marginal oil and gas fields through a cluster development approach.” The last priority is looking into new resources such as tight gas, coal bed methane and shale gas While no one is counting on a new giant discovery, there is an impressive amount of exploration and development work under way, which combined certainly has the potential to reverse the recent declines in output. That includes new discoveries that are under development, enhanced recovery programmes for older fields, a number of exploration initiatives and strategies being devised with Malaysia to jointly produce fields near maritime borders.
Applied Science
The beginning of the modern age of oil and gas exploration and development in Brunei Darussalam is probably best dated to 2005 with BSP’s Champion West field, a satellite of the giant Champion offshore oil field. Champion West was discovered in 1975, but for decades was considered too difficult to be commercially viable. Although under only about 40-50 metres of water, the field’s oil and gas are between 2 km and 4 km further down below the sea floor. What’s more, the resources are scattered in about a thousand small, vertically stacked reservoirs over a 12-km-by-3-km area.
The project became a showcase of the “smart fields” and “snake well” technologies employed by Shell, which has been the main foreign player in the country’s oil and gas industry since the 1920s. BSP produces around 90% of Brunei Darussalam’s oil and gas and operates the Champion field, as well as its satellites. Snake wells begin by drilling down, then turning roughly 90° and burrowing on a winding, horizontal path that allows producer to tap into multiple reservoirs and reduces the chance of any oil being left behind, as well as contributing to lower costs. The longest such well at Champion West exceeds 8 km in total length. Smart fields technology combines digital sensors on wells with real-time monitoring and control systems that allow for automatically adjusting and optimising production. The technology can improve oil and gas recovery, as well as optimising the production.
Positive Results
The application proved highly successful and by 2007 Champion West accounted for about 20% of BSP’s oil output. BSP used a similar combination of technology in 2009 to expand output of the smaller Bugan field. France’s Total then discovered a field even deeper under the sea floor to the south of the Maharaja Lela/Jamalulalam (MLJ) field, where Total has been producing mostly gas since 1999. Total operates MLJ South with a 37.5% stake to Shell’s 35% and the Brunei National Petroleum Company’s (PetroleumBRUNEI) 27.5%. As part of a 2007-10 exploration campaign, Total discovered the southern satellite field between 4 km and 5.8 km below the sea floor.
Extreme pressure of up to 16,800 pounds per square inch make MLJ South a very challenging and costly project, but Total is moving ahead after receiving a 20-year extension of its contract governing the area, called Block B. Total executives have said MLJ South has an estimated resource base of 150m barrels of oil equivalent and is expected to boost the company’s gas sales by 82m cu ft per day. That is equal to about 7% of Brunei Darussalam’s total gas output in 2012, according to US Energy Information Agency data. The project took a step forward in early 2014 with the award of three large contracts to build and install a wellhead platform and upgrade an onshore processing plant and pipelines.
Other Alternatives
Since 2008 BSP has been applying another advanced drilling technology to tap difficult corners and offshore satellites of the giant onshore Seria field, where Brunei Darussalam’s oil industry first began. Called “fishhook wells” because of their characteristic downward then upward curve, BSP has drilled wells as tightly angled as 141°. Meanwhile, BSP has been steadily bringing a string of small shallow offshore fields on-line, including the Mampak field in 2009, the Selangkir field in 2011, the Danau-Bubut field in 2012, the Champion North field in 2013 and the Osprey field, which is set to begin production in 2014.
Going Deep
Brunei Darussalam sought to kick off deepwater exploration in 2001 with a 3D seismic mapping project of some 10,000 sq km of its offshore shelf. While there was some tension with Malaysia over the area as the country moved to tender out the area, an agreement was reached in 2009 that recognised the Sultanate’s sovereignty over the shelf while bringing the winners of both Brunei Darussalam and Malaysia’s tenders into new production sharing contracts (PSCs), signed in 2010.
Total is also preparing to further explore its huge deepwater Block CA1. According to a recent company statement, “Surveys to re-appraise the block’s potential are under way and should result in a new exploration strategy.” In the north-eastern half of the area, known as Block CA1, Total is the operator and holds a 54% stake, followed by BHP Billiton with 22.5% and Hess Corporation with 13.5%, and 5% stakes each for Murphy Oil and Malaysian state oil and gas company Petroliam Nasional (Petronas). In Block CA2, the south-western half, Petronas is operator with a 45% stake to Murphy’s 30%, Shell’s 12.5%, and 6.25% stakes for Conoco and Mitsubishi.
Looking For New Possibilities
Meanwhile, BSP ended up doing the first deep offshore drilling in 2009 in a corner of its acreage it had been holding in reserve. The area is about 1 km deep and 100 km offshore, and is adjacent both to Block CA1 and to an area of Malaysian offshore where Shell is operator. Shell had also recently discovered a large field known as Gumusut-Kakap on the Malaysian side. In 2011 BSP announced a “major” discovery it called the Geronggong field, which it said may “contain several hundred million barrels of oil”.
However, the exploration in the huge CA1 and CA2 blocks has so far produced largely lacklustre results. Total’s initial exploration programme in CA1 in 2012 was “disappointing” according to its annual report, with only a small discovery it called Jagus East, adjacent to both Geronggong and Gumusut-Kakap. Petronas’ initial exploration programme in CA2 in 2013 generated excitement when Malaysian Prime Minister Najib Razak announced in December 2013 that Petronas had made a “commercially viable” discovery. Both Murphy Oil and PetroleumBRUNEI later confirmed a discovery had been made, but as of August 2014 the scale of the find remained unclear as Petronas had yet to make any further statements.
According to the EDPMO, Petronas was still studying its drilling results and the majority of deepwater development would be in the long term. The volumes in the CA2 deepwater block are expected to be big enough to develop, but for now are only being booked as resources. It could take up to five to 10 years before they can be booked as reserves.
Revisiting Shallow Water
When PM Najib made the announcement during a visit to Brunei Darussalam in December 2013, he and Sultan Hassanal Bolkiah had signed a bevy of agreements deepening the country’s cooperation with Malaysia in the oil and gas sector. Among them was a deal to award two shallow offshore blocks to Petronas and Shell, called Blocks N and Q. Reconstituted from pieces of blocks that had been previously awarded and relinquished, the fields are not considered the most promising prospects in Bruneian offshore, but they are likely to contain more recoverable reserves with modern technology than previous operators estimated. Shell and Petronas were awarded 50% stakes in each of the two blocks, with Petronas the operator of Block N, which lies nearest to shore, and Shell the operator of Block Q. Brunei Darussalam closely guards the details of its PSCs, but terms for the rehashed blocks are thought to be relatively favourable. As of August 2014 exploration programmes for them had not yet been announced.
PetroleumBRUNEI is mulling its options for another farther 1021-sq-km offshore area called Block P, similarly rehashed from previously licensed and relinquished blocks. Exploration of two large onshore blocks by minor international firms was unsuccessful, with Poland’s Serinus Energy suspending exploration in Block L in late 2013. Serinus had a 90% stake in the field through two wholly owned subsidiaries. The company announced its withdrawal in late 2013 after drilling to 1720 metres. A consortium of small firms also relinquished Block M in 2012.
Meanwhile, according to the EDPMO, Shell was preparing an exploration programme for Block A, where it is operator with a 53.9% interest to PetroleumBRUNEI subsidiary PB Expro’s 46.1%. The shallow offshore block was previously explored by Total’s predecessor Elf, which in 1988-89 discovered two small fields that were then considered non-commercial, namely, Juragan and Perdana.
Getting Unitised
Also announced in December 2013 were important agreements to launch negotiations towards unitising fields near the two countries’ maritime borders. Unitisation refers to the process of combining two or more areas licensed to different oil and gas exploration companies under a single operator in order to make development more efficient, and/or fairly share the output of fields that straddle the borders between two companies or consortiums’ licensing blocks and/or two countries’ international borders. Brunei Darussalam and BSP previously completed two such unitisations with Malaysia and its licensees for fields that straddle the South-east Asian countries’ maritime borders.
Reviving An Old Giant
Also under way is a major investment by BSP in a new project in order to maximise output from the ageing Champion field. Called the Champion Water Flood Project, the scheme will flush hard-to-reach oil up from larger and more depleted oil reservoirs by flooding them with a mix of water and a specially designed cocktail of alkaline surfactant polymers that had previously been used at Seria. Because Champion’s reservoirs are widely spread and fragmented, the project will require drilling up to 150 injection wells from 12 platforms.
BSP first began awarding contracts for the project in 2012, and the third phase is planned to start in 2017, although the last and final phase has not yet been scheduled. BSP has also said it expects the project to increase oil recovery from the Champion field by about 200m barrels and to extend the field’s life by up to 30 years. BSP is also considering a large-scale enhanced oil recovery project at Seria, where it first tested the technology on a pilot well in 2010.
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