Regional Report: Southeast Asia/Australia

With a dense population and, therefore, a growing energy demand, Southeast Asia relies heavily on the oil and gas industry. This urgency has given rise to the region’s E&P efforts during an industry downturn, as producers have been forced to contend with low prices and aging fields.

THAILAND/VIETNAM/BRUNEI

Thailand. While the Kingdom of Thailand is primarily an energy importer, it still identifies as a chief Southeast Asian producer of natural gas. Its estimated reserves are presumed to be at least 10 Tcf.

Fig. 1. In April 2016, Mubadala Petroleum concluded drilling of two development wells as part of the Manora Oil Development JV. Image: Tap Oil.

Mubadala Petroleum announced that drilling of the MNA-15 and MNA-16 development wells had concluded in April 2016. Situated in the northern Gulf of Thailand, the wells are part of the Manora Oil Development JV between Mubadala Petroleum (operator, 60%); Tap Oil (30%); and Northern Gulf Petroleum (10%), Fig. 1.

MNA-15 found 144 ft of oil pay in three separate reservoirs, while MNA-16 encountered 121 ft of oil pay in four separate reservoirs. Drilled to TDs of 8,418 ft and 9,835 ft, respectively, the wells are reportedly expected to return Manora oil field to its peak production rate of 15,000 bopd (gross). The field, found nearly 50 mi offshore, is believed to hold an estimated 20 MMbbl of oil (gross), overall.

Tap Oil went on to complete drilling of the MNA-17 appraisal well in September. The well, also in the northern Gulf of Thailand, was drilled to a depth of 6,508.8 ft TVDSS. It was reported that 57 ft of oil pay were found in four separate reservoirs.

Vietnam. Rosneft Vietnam BV began drilling the PLDD-1X exploration well in Block 06.1, offshore Vietnam, in March 2016. With estimated recoverable natural gas reserves of about 12.6 Bcm and 0.6 mt of gas condensate accessible within the geological structure, Rosneft signed an agreement with Japan Drilling Co. for the HAKURYU-5 drilling rig. The company reported that the resources may be developed through subsea completions, and tied-back to the existing Lan Tay platform, which Rosneft operates in Block 6.1.

Following the drilling of PLDD-1X, the company reportedly will drill another exploration well in Block 05.3/11, also found in the Nam Con Son basin. Both wells will be incorporated into the same drilling program. Additionally, Rosneft announced plans to shoot broadband 3D seismic on its existing Block 6.1, in an effort to heighten ongoing production recovery and explore deeper prospects.

Brunei. Brunei Shell Petroleum Company Sdn. Bhd. awarded a multi-year contract to McDermott International in June. The contract reportedly will see McDermott carry out pipeline work that includes transportation and installation (T&I) of pipelines and umbilicals in Fairley and Ampa fields, offshore Brunei. The 2017 campaign will ostensibly include T&I for 20 mi of pipelines, as well as ancillary crossings, tie-ins, riser installation and pre-commissioning of the completed system.

“Brunei has significant long-term plans to increase investment and production in its energy sector, and the successful installation of these new pipelines in Ampa and Fairley fields is expected to help ensure production continuity of the mature reserves,” said Hugh Cuthbertson, V.P., Asia. “Our contribution in developing these facilities plays a vital role in helping Brunei Shell Petroleum meet its production targets, and Brunei meet its energy goals.”

MALAYSIA

Despite having the fourth largest reserves in the Asia-Pacific region, Malaysia was affected significantly by the industry downturn. In February 2016, Petroliam Nasional Bhd. (Petronas), Malaysia’s state oil company, reported its third loss in five quarters. Following the loss, the company restructured its business in an effort to cut spending, resulting in the loss of about 1,000 jobs.

Petronas was one of multiple non-OPEC producers to agree to a voluntary cut in oil production at the beginning of this year. Malaysian oil production will be adjusted by up to 20,000 bopd, according to Petronas.

Malaysia is an energy producer that focuses largely on its offshore resources. Lundin Petroleum has been actively exploring offshore Malaysia for years, and is the operator in six blocks. Last year, the company completed the Bambazon exploration well in Block SB307/SB308. According to Lundin, the well encountered approximately 49 ft of net logged reservoir pay, with oil shows over three main reservoir intervals.

At that same time, and in the same block, Lundin drilled the Maligan exploration well with the West Prospero jackup rig. The well—which is positioned just north of a major producing field, offshore East Malaysia—was drilled to target hydrocarbons in Miocene-aged sands. By March, after reaching a TD of about 4,527 ft, it was reported that the Maligan well had uncovered significant gas shows. It was subsequently plugged and abandoned.

Malaysia was preparing for its first tension leg platform (TLP) in June. The TLP was installed in 1,640 ft of water at Shell’s Malikai field, about 62 mi offshore Sabah. Malikai is a JV project between Shell (operator, 35%), ConocoPhillips Sabah (35%) and Petronas Carigali (30%). After installation, the deepwater platform began producing in December, with an anticipated peak production of 60,000 bopd.

Simon Ong, managing director of projects and technology for Shell Global Solutions Malaysia, said: “Deep water is a growth priority for Shell, and our Malikai project supports the country’s aspiration to be a hub for deepwater development in the region.”

In October, Royal Dutch Shell was said to be considering the sale of its 15% stake in MLNG Tiga Sdn., the owner of an LNG export terminal in Sarawak, on the island of Borneo. The sale, which reportedly could draw more than $1 billion, is part of Shell’s strategy to raise $30 billion over the next three years, following it’s BG Group acquisition.

Also offshore Sarawak, Petronas’ first FLNG facility, PFLNG SATU, produced first gas from Kanowit gas field in December. The facility is a major milestone for the company, boasting a processing capacity of 1.2 mtpa. Commercial operations are expected to begin first-quarter 2017.

INDONESIA

With significant energy resources, the Republic of Indonesia is a major producer and exporter. Its muddled OPEC membership has seen it in, and out, of the organization since 1962, when it first joined. The country suspended its membership in January 2009. It rejoined OPEC in January 2016, only to suspend its membership once again in November. Despite its indecision, Indonesia continues to be an influential part of Southeast Asia’s oil and gas industry.

In early February 2016, it was reported that Cue Energy Limited had discovered oil in Indonesia’s Kutai basin. The Naga Selatan-2 (NS-2) well reached a TD of 1,170 ft, and was subsequently suspended to allow prospective production testing. The NS-2 well, which is 100% operated by Cue Energy, successfully authenticated a play concept comparable to Sanga Sanga fields, found nearby. The company reported that the “use of appropriate technologies [would] be used to further delineate the sweet spots along the anticlinal axis.”

Fig. 2. The final investment decision for the development of the Tangguh Expansion Project, in Indonesia’s Papua Barat Province, was approved last June. Operations are expected to begin in 2020. Photo: BP.

A few months later, in June, Santos reported a successful drill stem test (DST) on the G Sand reservoir at its AAL-4XST1 appraisal well. The offshore test achieved an average flowrate of 828 bopd, stabilized over a 9-hr period. Because results exceeded expectations, bulk oil samples were collected for further testing. Produced gas and water rates, however, were too low to accurately measure. Operations were then initiated for a second DST test in the AAL field K Sand reservoir.

The final investment decision (FID) for the development of the Tangguh Expansion Project, in Indonesia’s Papua Barat Province, was approved in June. The project, which is a production sharing contract between BP and several partners, will see the addition of a third LNG process train, as well as 3.8 mtpa of production capacity. This will bring total plant capacity to 11.4 mtpa. Additionally, the project includes two offshore platforms, 13 new production wells, and an expanded LNG loading facility.

The Tangguh LNG plant sources gas from six fields (Fig. 2), including Vorwata, Wiriagar Deep, Ofaweri, Roabiba, Ubadari and Wos. Its expansion is expected to aid in fueling Indonesia’s growing energy demand, and will reportedly begin operating in 2020. BP Group CEO Bob Dudley said, “The Tangguh Expansion Project demonstrates BP and its partners’ continued confidence in Indonesia, and our commitment to work closely with the government to meet the country’s energy needs, while creating thousands of jobs.”

Ophir Energy reported the start of commercial production from Kerendan field, onshore Central Kalimantan, in September. Ophir holds a 70% operating interest in the field, while Bangkanai PSC and PT Saka Bangkanai Kalimantan holds a 30% equity interest. Following first production, sales were reportedly being limited to 5 MMscfd, first meeting demand for power in the Buntok region. However, production is expected to increase to approximately 20 MMscfd.

PAPUA NEW GUINEA

In recent years, Papua New Guinea has become a competitor in the energy market, as it boasts considerable natural gas reserves and is opportunely located. The South-Pacific LNG producer and exporter has easy access to Asian consumers, including Korea, China and Japan.

InterOil Corp., an exploration and development company that primarily focuses on operations in Papua New Guinea, holds equity in four exploration and two production retention licenses in the country’s Eastern Papuan basin. The area is somewhat underexplored when compared to the Western Papuan basin. However, the company has, thus far, a total of five discoveries in the basin—including Raptor, Bobcat, Elk, Antelope and Triceratops.

It was announced in May 2016 that InterOil’s assets would be distributed among both Oil Search and Total. Both companies are said to be in pursuit of LNG export growth in the region. Oil Search offered to acquire 100% of the explorer for $2.2 billion. Likewise, Oil Search and Total had expressed interest in increasing their shares in Papua New Guinea’s only LNG terminal, Exxon Mobil-operated PNG LNG.

Nevertheless, Exxon Mobil submitted an offer of $2.5 billion for InterOil’s Papua New Guinea natural gas assets, outbidding Oil Search. It was reported in July, however, that Exxon may pay up to $3.6 billion to acquire InterOil Corp. and its assets. It subsequently raised its bid to $3.9 billion. Yet, the offer wasn’t enough to satisfy InterOil’s founder and third-largest shareholder, Phil Mulacek, who deemed the proposal “ethically flawed.” InterOil has scheduled a shareholder vote, regarding Exxon’s newest proposal, for mid-February 2017.

There are also reported plans to expand the PNG LNG project, which presently sources gas from Hides, Angore and Juha gas fields, as well as from associated gas in Kutubu, Agogo, Moran and Gobe Main oil fields. Expansion of the project would primarily see resources sustained through P’nyang gas field, about 74.5 mi northwest of Hides field. According to Oil Search, who holds a 29% interest in the project, more than 9 Tcf of gas and 200 MMbbl of associated liquids are expected to be produced during the project’s projected 30-year lifespan.

Total operates Papua New Guinea’s second LNG venture, which doesn’t expect first gas until after 2020. The project, Papua LNG, is a JV between Total, InterOil, Oil Search and Papua New Guinea’s government. Close to the country’s capital, Port Moresby, in the Eastern Papuan basin, Papua LNG will be sustained through the Elk-Antelope gas fields, about 211 mi from the plant.

According to BMI Research, Papua New Guinea’s exports could be boosted to more than 20 Bcm by 2024 with the construction of Papua LNG. This is a dramatic upswing when compared to the 8.76 Bcm exported in 2015. Oil Search says that a comprehensive appraisal program is already underway.

In December, Exxon Mobil announced a new natural gas discovery in Papua New Guinea’s North Highlands, about 13 mi northwest of Hides field. The Muruk-1 exploration well was drilled to a depth of 10,630 ft, and encountered high-quality sandstone reservoirs. Appraisal is reportedly now underway in an effort to determine the size of the resource discovery.

AUSTRALIA

Australia dominates the South Pacific region in terms of E&P activity. Bloomberg even reported last year that a recent bout of Australian investment has put the country on course to surpass Qatar as the world’s largest LNG producer.

Some major producers, however, are reportedly making plans to sell much of Australia’s depleting energy assets, in an effort to rid themselves of the high cost associated with mature fields. For instance, Exxon Mobil and BHP Billiton have expressed interest in promoting the sale of 13 Southeast Australian fields, licenses and auxiliary infrastructure in the country’s Gippsland basin JV—which collectively produce about 19,000 boed. This includes Kingfish field, Australia’s first offshore oil field, and its largest.

Woodside completed its acquisition of 50% of BHP Billiton’s Scarborough assets in November. The assets acquired—including Scarborough, Thebe and Jupiter gas fields—are situated offshore Western Australia, in the Carnarvon basin. Collectively, the fields are estimated to contain about 8.7 Tcf (gross) of dry gas resources. The $250-million purchase includes a 25% interest in WA-1-R and a 50% interest in WA-61-R, WA-62-R and WA63-R.

In July 2016, Australia saw several achievements, as well as setbacks. Falcon Oil & Gas successfully spudded its Beetaloo W-1 vertical well, in Australia’s Beetaloo basin. The well, Falcon’s fourth well of its nine-well drilling and evaluation program, was reportedly targeting the southern part of the basin, which is generally underexplored. It is found nearly 53 mi south of the company’s first well, Kalala S-1, and is projected to reach a TD of approximately 9,990 ft.

Falcon, with its JV partner, Origin Energy Resources, reported another find in October. The A Mungee NW-1H well, which is also in the Beetaloo basin, showed gas rates ranging from 0.8 to 1.2 MMcfgd, with “continuing flowback of hydraulic fracture stimulation fluid of volumes between 100 and 400 bpd.”

Conversely, in July, Chevron faced its second setback in output at its Gorgon LNG development, on Barrow Island, offshore Australia’s northwestern coast. A minor gas leak at the $54-billion mega-project forced the company to shut down operations. Production, however, restarted just days later.

The following month, in August, Cooper Energy spudded Callawonga-12, an oil development and appraisal well on the western flank of South Australia’s Cooper basin. The well, situated approximately 1,082 ft northeast of the Callawonga-1 production well, is expected to drill to a depth of about 4,750 ft. It reportedly will accelerate reservoir production, and potentially add reserves.

Beach Energy, too, spudded an exploration well on the western flank of the Cooper basin. The well, Penneshaw-1, was being drilled nearly 3 mi west of Christies field, to a TD of about 6,108 ft. As the well is drilled in the Merrimelia formation, its primary target reportedly is the Namur sandstone, which is the oil producing reservoir in several nearby fields, including Christies field.

Bengal Energy announced a discovery through its Cuisinier 2016 five-well drilling program in September. The company’s Australian assets are also in the Cooper basin, primarily in the southwest part of Queensland. The Cuisinier campaign’s first four wells were “cased as future oil producers in the Murta horizon.” The Shefu-1 exploration well was drilled on the PL 303 lease, about 2.2 mi west of the development well, Cuisinier-17. It encountered 26.5 ft of gross sand, with nearly 23 ft of net pay. Following the discovery, the rig was reportedly being moved to begin drilling of the fifth, and final, well.

Chayan Chakrabarty, president and CEO of Bengal, said, “While further testing is needed to illustrate the full production potential from the Shefu-1 well, expanding the known oil-in-place at Cuisinier further confirms the excellent new reserves potential, and supports our overall plan to continue developing the multiple commercial finds at the Barta Permit.”

Karoon Gas Australia entered the Great Australian Bight (GAB), offshore Australia, in October. The company was awarded a license for exploration permit EPP46, which covers approximately 11,056 mi2. It is found in Australia’s most prospective frontier oil province, the Ceduna sub-basin. The company said that it believes the sub-basin could be “a globally significant hydrocarbon province with world-class potential.”

As Karoon was seen entering the region, BP made the decision to exit the GAB, abandoning all exploration activity in the region. It was reported that the decision was based solely on the industry’s price environment. At the same time, however, BP acquired 80% of the WA-409-P permit, as well as an option to acquire 42.5% of the WA-359-P permit from Cue Energy Resources. The company said that its new offshore fields are aimed at increasing supply for the North West Shelf LNG venture, Australia’s largest resource development project.