As a subregion of Asia (the world’s biggest oil market), Southeast Asia and Australia play an integral role in the supply of regional energy demand. Accordingly, as prices rise, the region’s E&P sector is being resurrected, and major projects are getting off the ground.
As Southeast Asia’s biggest gas supplier, the Indonesian archipelago is an increasingly valuable region for E&P activity. Nevertheless, in recent years, the resource-rich nation has experienced a decline in oil revenue, as well as a steady rise in fuel imports.
In April 2017, Bloomberg reported on Indonesia’s plans to overhaul its energy policy, in an effort to attract up to $200 billion in investments over the next decade. The policy amendments, which are intended to help the country reverse its recent decline in production, would permit tax-free importation of drilling equipment and technology for explorers in the region. Additionally, Energy and Mineral Resources Minister Ignasius Jonan said the nation planned to offer 14 unexplored oil and gas blocks to help attract investors.
Major progress was made in the country’s offshore sector, however, as Eni (55%) announced first gas from the Jangkrik Development Project in May. The development, situated in the deep waters of the Makassar Strait, contains Jangkrik and Jangkrik North East gas fields. It includes 10 deepwater subsea wells, which are connected to the Floating Production Unit (FPU), Jangkrik. According to Eni, start-up of the project was achieved ahead of schedule and will supply approximately 83,000 boed to Indonesia’s domestic demand, as well as to its export market. Eni’s partners include Engie E&P (33.334%) and PT Saka Energi Muara Bakau (11.666%).
Likewise, CNOOC (40%) reported first gas at BD field in August. The field is in the Madura Strait, offshore East Java. When first gas was reported, the company said two of four wells were producing, and peak production of 25,500 boed was anticipated for this year. The production facilities also include an unmanned wellhead platform and an FPSO. CNOOC’s partners include Husky (40%) and Samudra Energy (20%).
In the Indonesian province of West Sulawesi, Sonoro Energy announced a discovery at its LG-1 up-dip well (Fig. 1), on the Budong Budong PSC lease. According to a company release, preliminary tests showed an interval of 259 ft of reservoir sandstones suffused with shales in the Lisu formation. Richard Wadsworth, CEO and director at Sonoro Energy, said, “We also remain confident that a much larger opportunity exists in the Budong Budong Production Sharing Contract, as similar shallow prospects have already been mapped at the Pliocene Lisu formation level—several of which appear to be much larger in area than the LG formation.”
According to the EIA, Malaysia ranked as the third-largest exporter of LNG, after Qatar and Australia, in 2016. Shell’s Gumusut-Kakap and Malikai fields, however, are some of the country’s chief producing assets. The platform at Gumusut-Kakap field, which is situated in a water depth of about 3,900 ft, reportedly contributes up to 25% of the country’s oil output. It was Shell’s first deepwater project in Malaysia and has an annual peak production of approximately 148,000 bopd. Similarly, Malikai employs the country’s first TLP, which has an average annual peak production of about 60,000 bopd. It is situated about 60 mi off the coast of Sabah, in a water depth of approximately 1,640 ft.
International Petroleum Corp. (IPC) recently began drilling the first two infill wells planned for Bertam field, 108 mi offshore Peninsular Malaysia, in Block PM307. Bertam field includes an unmanned wellhead platform and 12 horizontal wells, which produce to a moored FPSO. As of year-end 2016, the field has net 2P reserves of 9.5 MMboe remaining. According to IPC, the infill wells are targeting gross best-estimate contingent resources of about 2.3 MMboe. The drilling campaign was scheduled to conclude by the end of February 2018.
Roc Oil reported that the A5 well started producing in October. The well—drilled in the D21 field, within the western Balingian province of the Sarawak basin—was part of a four-well drilling campaign for the D35, D21 and J4 PSC. According to the company, the successful drilling campaign has led the firm to believe that there is potential to uncover more reserves than initially projected. The next drilling campaign, at J4 field, is scheduled to commence in November.
The government of Vietnam granted formal approval to the Te Giac Trang (TGT) field development plan last February. TGT field lies in Block 16-1, in the Cuu Long basin, off Vietnam’s southern coast. Crude oil from the field is transported via subsea pipeline to the Armada TGT 1 FPSO, and gas is transported via pipeline to the nearby Bach Ho facilities. The approved field development plan reportedly includes up to 18 additional wells and new processing equipment on the H1-WHP platform. According to SOCO Vietnam (part of Hoang Long Joint Operating Company), the new processing equipment will be outfitted to handle 90,000 bbl of liquid per day.
Thailand’s domestic production has faded in recent years, resulting in an increased reliance on imports. According to the EIA, the country’s total oil consumption is estimated at nearly 1.3 MMbpd (2016), which is more than twice the country’s petroleum liquids production. Last year, the country reported plans to boost its LNG imports by up to 70%, to satisfy demand.
E&P activity continues throughout the kingdom, however. In May, Ophir Energy announced that an FID had been taken for the fourth phase of the Bualuang oil field development, in the Gulf of Thailand. The $145-million development reportedly will include a 12-slot, bridge-linked wellhead structure with additional power generation. The company reported that it also will include the drilling of up to 14 wells, as well as an expansion of the water disposal capacity on the Bravo platform. It is expected to convert approximately 9.2 MMbbl of contingent resources to reserves, and first oil is anticipated by the end of this year.
KrisEnergy has been an active operator in the region, as well. In October, the company announced that drilling of the East Mayura-1 exploration well had begun in the Gulf of Thailand. The well is reportedly the first to be drilled in a prospective eight-well drilling program. It is situated in the G10/48 contract area (Fig. 2), which covers approximately 1,677 km2 across the Southern Pattani basin. The area contains the Wassana, Niramai, Mayura and Rayrai oil discoveries.
The Kingdom of Cambodia is seeing progress on several fronts. The country, previously known as a Least Developed Country (LDC), raised its economic status in 2016 to a Lower-Middle Income Country. The following year, the government sealed terms for the nation’s first hydrocarbon development project in Cambodia Block A, in the Gulf of Thailand.
The Royal Government of Cambodia (5%) signed an agreement with KrisEnergy (95%) in August. As operator of Block A, KrisEnergy proceeded to make a final investment decision on the first phase of development in October. The Apsara project is situated in the northeastern section of the concession, and could take up to a year before reaching first oil.
According to KrisEnergy, reservoir production performance in the Khmer basin has yet to be proven, which generates some “uncertainty” regarding long-term production rates, reserves and commercial viability. Because of this uncertainty, the company says it will develop the Apsara project in phases. Phase 1A reportedly will see the development of a single, unmanned, minimum-facility 24-slot wellhead platform, which will produce to a moored production barge with a processing capacity of up to 30,000 bbl of fluid per day.
In May, Total reported the start of production at Myanmar’s Badamyar project, nearly 137 mi south of Yangon. The project includes a new wellhead platform, which is connected to the Yadana production facilities, supporting an extension of Yadana gas field’s 8 Bcm/year production through 2020. Additionally, the project includes the drilling of four horizontal wells, developing Badamyar field as a satellite of Yadana.
With the 13th-largest economy, the Commonwealth of Australia is home to some of the world’s most expansive and expensive LNG projects.
Chevron’s Gorgon LNG plant, which is the continent’s largest development, saw several setbacks last year. The project has faced numerous interruptions since its start-up in March 2016, including a number of outages and a shutdown of Train 1 that lasted for almost an entire month. The $54-billion project has a production capacity of approximately 2.6 Bcfg and 20,000 bcpd. It is situated on Barrow Island, about 37 mi off Australia’s northwestern coast, and includes an LNG facility with three processing units.
Despite the setbacks at Gorgon, Chevron announced a major milestone at its Wheatstone project, also in Western Australia. About 7.5 mi west of Onslow, the two-train LNG facility began processing natural gas from Wheatstone and Iago fields in October. At full capacity, it will supply approximately 8.9 million metric tons per year to buyers in Asia.
Early last year, Senex Energy allocated $50 million for a 30-well drilling campaign at the Western Surat gas project, north of Roma in Queensland. The work program was announced after pilot wells at Glenora Block were brought online in February 2017. Additionally, the company reported signs of strong gas flows at the Eos Block. Both blocks are situated in the southeastern part of the project. Senex anticipates up to 0.6 MMboe by mid-year.
In June, Statoil was granted the regulatory approval necessary to extend its work program in the Great Australian Bight, off the southern coastline of Australia’s mainland. In addition to the extension, which includes the drilling of one exploration well, Statoil took over exploration permits EPP39 and EPP40 from BP. Likewise, BP took over exploration permits EPP37 and EPP38 from Statoil. “We have a good understanding of the geology in our license area, based on high-quality 3D data analysis. We believe there could be an active petroleum system within our position in this promising, unproven basin with a large exploration upside. This is in line with Statoil’s global exploration strategy of accessing at scale and targeting high-impact opportunities,” said Pål Haremo, Statoil’s V.P. of exploration in Australasia.
At the end of July, BP made another big announcement regarding its operations in Australia. The oil giant’s Persephone project, which is part of the North West Shelf Project JV and operated by Woodside Energy (16.67%), came onstream. The project—which is approximately 86 mi northwest of Karratha, in Western Australia’s Pilbara region—is made up of two subsea wells that are tied back to the North Rankin complex by a 4-mi flowline. According to BP (16.67%), the complex has a daily production capacity of about 66,000 tonnes of dry gas and 6,000 tonnes of condensate from North Rankin and Perseus fields. At peak production, the project will be pumping about 48 MMcfd of gas net. BP and Woodside also are partnered with BHP, Chevron, Shell and Mitsubishi-Mitsui (16.67% each).
Shell and INPEX Corp. saw important milestones in 2017, as well. Shell’s Prelude floating liquefied natural gas (FLNG) facility arrived at the Prelude gas field in July (Fig. 3), about 295 mi northeast of Broome. This is the company’s first time deploying the FLNG technology, which will extract and liquefy gas at sea before exporting it to buyers. Shell says it expects to see cash flow from the project sometime this year.
Likewise, INPEX reported the arrival of the Ichthys LNG project’s FPSO facility, Ichthys Venturer. In August, the FPSO was successfully moored at Ichthys field, approximately 136 mi off the northern coast of Western Australia. It is situated about 2 mi from its sister facility, Ichthys Explorer, in about 820 ft of water. At more than 1,100 ft long, the colossal FPSO reportedly is designed for 40 years of operations without dry dock. It has a storage capacity of 1.12 MMbbl of condensate. Louis Bon, the project’s managing director, said that after mooring, the FPSO will now undergo hook-up and commissioning to support the safe, reliable start-up of operations.
In September, Northwest Energy reported the discovery of hydrocarbons at its Xanadu prospect, in shallow water about 24 mi south of Dongara. The Xanadu-1 well was drilled from an onshore surface location (Fig. 4) to an offshore target in the northern Perth basin, reaching a TD of 2,035 mMDRT. With unrisked recoverable resources of about 160 MMbbl, the company says it is one of the largest untested oil targets in the basin. Following the Xanadu-1 well results, Northwest Energy says there is an “excellent chance” of finding a much larger column in an up-dip location from the same drilling pad.
Beach Energy announced a recent discovery, as well. Last month, the company reported a new gas find at Haselgrove-3 ST1 in the Otway basin, onshore South Australia. It is situated on state forestry land in PPL 62, about 4 mi south of Penola. The well reportedly intersected an estimated gross gas column of 341 ft, TVT (total vertical thickness), in the Sawpit Sandstone, with estimated net pay of 83 ft, TVT. Additionally, the company reported that an estimated gross gas column of 38 ft, TVT, was intersected in the more shallow Pretty Hill Sandstone, with an estimated net pay of 27 ft, TVT. The well was shut in, and an initial production test was scheduled to take place by the end of the month, which reportedly will help confirm well deliverability and gas composition. The company said that field development planning would subsequently commence.
PAPUA NEW GUINEA
Just north of Australia, Papua New Guinea’s (PNG) E&P sector continues to evolve. Oil Search, one of the largest producers in the region, reported that production at its PNG LNG project hit record levels last year. The company said output reached 8.65 MMtpa in June, which reportedly is about 25% above nameplate capacity. The project, operated by ExxonMobil PNG Limited, sources gas from Hides, Angore and Juha fields, and associated gas from Kutubu, Agogo, Moran and Gobe Main fields. According to Oil Search, the project is expected to produce more than 9 Tcf of gas and 200 MMbbl of associated liquids over the course of its 30-year lifespan.
Santos, another leading producer in the Asia-Pacific region, and ExxonMobil reported positive results from its Muruk drilling program, about 13 mi northwest of the Hides production facilities in the PNG Highlands. According to Santos, well logs and pressure data from the Muruk-1 exploration well confirmed that the entire Toro reservoir section was gas-saturated, and a potential appraisal program is anticipated to commence this year. “This important discovery confirms the extent of the Muruk area, and further establishes Muruk as a potentially significant new discovery with the same high-quality sandstone reservoirs as the Hides field that underpins the PNG LNG project,” Steve Greenlee, president of ExxonMobil Exploration Company, said in a release.
Just last month, ExxonMobil reported another discovery in PNG’s Western Province. The P’nyang South-2 well encountered high-quality, hydrocarbon-bearing reservoirs in the Toro and Digimu sandstones, after being drilled to a depth of 8,940 ft. The operator said that evaluation of the well results are underway to assess the resource potential of P’nyang field.
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