Southeast Asia continues to plan its energy future

Despite economic woes, operators maintain busy drilling schedules through 2010.  

Jeanne M. Perdue, Contributing Editor

Drilling activity remains fairly lively in Southeast Asia despite the recent global downturn, although some of the smaller producers are keen to farm out interest to other companies to generate enough cash flow to go forward with some of their more promising projects. Here is World Oil’s summary of the region’s latest E&P activities.

VIETNAM
The Vietnamese government has approved the application for the Te Giac Den (TGD) and Voi Trang (VT) appraisal areas in Block 16-1 in the offshore Cuu Long Basin. Soco Vietnam holds a 28.5% working interest in Block 16-1, which is operated by the Hoang Long Joint Operating Company; Opeco Inc., a wholly owned Soco International subsidiary, holds a 2% interest.

The 150-sq-km TGD appraisal area includes the high-pressure, high-temperature TGD-1X-ST1 discovery well on Prospect E and the analogous E South Prospect. It is adjacent to Te Giac Trang Field, whose field development plan as of this writing was expected to be approved by June 2009, with first oil planned for mid-2011. Seismic reprocessing over the TGD appraisal area is underway with final results expected in September 2009, and an appraisal well is being planned for a spud date in second-quarter 2010.

The 100-sq-km VT appraisal area is undergoing a technical evaluation of the discovery well and adjacent offsets to assess reserves and commerciality, with preliminary results expected in June 2009, as of this writing.

“Vietnam governmental approval of the appraisal areas puts us in the position to finalize our evaluation of the remaining potential in our current Vietnam portfolio within 18 months,” said Soco President and Chief Executive Ed Story. “We believe that the HPHT play area has the potential to overshadow the already considerable success we have had in Vietnam to date.”

PetroVietnam signs two PSCs. PetroVietnam Exploration and Production Co. (PVEP) and Salamander Energy signed a production-sharing contract for Block 31 offshore southern Vietnam. Salamander is the operator with a 60% working interest. Block 31 covers more than 5,000 sq km and is adjacent to the Salamander-operated Block Cuu Long River Delta 01 (DBSCL-01) PSC. Recent 2D seismic indicates the presence of a high-quality source rock and multiple play types.

“Salamander has long since recognized Block 31 as attractive exploration acreage, and today’s announcement represents further progress in our building of an upstream business in Vietnam,” said Salamander Chief Executive James Menzies. “When taken together with Block DBSCL-01, we now operate a 13,000-sq-km swath of acreage across graben systems, which we believe are analogous to the highly prolific Cuu Long Basin, which lies to the east of our blocks.”

Geological and geophysical studies of the area are being conducted ahead of exploration drilling planned for 2010.

PetroVietnam signed a second PSC with Total for exploration blocks DBSCL-02 and DBSCL-03. Located in the Mekong Delta area onshore, these two blocks will be operated by Total with a 75% interest, with PVEP holding the remainder.

Block DBSCL-02 covers nearly 14,850 sq km, and Block DBSCL-03 covers nearly 13,800 sq km. Under the terms of the agreement, the first exploration phase will cover the acquisition of 2D seismic on each block.

PetroVietnam snags investment deals. State-owned Bank for Investment and Development of Vietnam (BIDV) is lending $76.82 million to PetroVietnam to hasten production at Mong Rong-Doi Moi Field in Block 09-3, located 135 km from the city of Vung Tau in southern Vietnam. The block is estimated to have 356 million bbl of crude oil and 57 Bcf of gas. PetroVietnam’s partners in the project are RVO Zarubezhneft of Russia and Japan’s Idemitsu Oil & Gas Co.

Canada’s Talisman Energy is investing $1.1 billion to develop two offshore Vietnamese oil fields: Hai Su Trang (White Sea Lion) and Hai Su Den (Black Sea Lion). These two fields in Block 15-2/01 are part of Talisman’s 60/40 joint exploration project with PVEP, called Thang Long Joint Operation Corporation. PVEP estimates Hai Su Trang Field to hold 59.6 million bbl of oil and Hai Su Den Field to hold 171.2 million bbl, and combined production of 36,000 bopd is expected when they come onstream in September 2011.

On April 22, 2009, Thang Long JOC signed contracts with a number of partners, including the Maritime Mechanical Service Company, the PetroVietnam Insurance Joint Stock Corp., Worley Parson-PetroVietnam JSC and PV Drilling, to develop the field.

“Oil discovered in the Hai Su Trang-1X and Hai Su Den-1X fields, 18 months after the company was formed, made Thang Long JOC one of the most successful companies ever to find oil in such a short period of time,” said company representative Paul Atkinson. “The JOC will waste no time putting the fields into production, which will help to maintain the country’s oil output after 2011, as well as ensure energy security.”

Serica signs farm-out with AWE. Serica Energy has agreed to farm out part of its interest in Block 06/94 offshore Vietnam to Australian Worldwide Exploration Ltd. (AWE), subject to government approval and waiver of a preemptive right held by PetroVietnam. A three-well drilling program for the Tuong Vi prospect in the Nam Con Son Basin began June 1, 2009, with the spudding of the 06/94-TV-1X exploration well, targeting the Dua Formation sandstones and the Nam Con Son carbonate. Block 06/94 is located about 400 km offshore Vietnam adjacent to the BP gas production facilities at Lan Tay and Lan Do.

Under the agreement, AWE will bear Serica’s 33.33% share of the drilling program’s costs to earn an interest of 23.33% in the PSC, with Serica retaining a 10% interest. Pearl Oil is the operator with 33.34% interest, and Lundin New Venture holds 33.33% interest.

MALAYSIA
Talisman Malaysia Ltd. has commenced oil production on schedule from the Northern Fields in the PM-3 commercial arrangement area offshore Malaysia and Vietnam. Talisman announced first gas production in July 2008 and has been ramping up since then. Total production is expected to reach 40,000–50,000 boepd by early 2010, with half going to Vietnam and half to Malaysia. Talisman plans to drill 16 development wells in the Northern Fields this year and 13 more in 2010.

Fig. 1. Talisman’s central processing platform at the Northern Fields project offshore Vietnam and Malaysia.

The overall project comprises about 70 reservoirs, 50 wells, three wellhead riser platforms, a central processing platform (Fig. 1), a floating storage and offloading tanker and more than 100 km of subsea pipelines. About $1.6 billion has been invested so far. Talisman Malaysia holds a 41.44% interest, while Petronas Carigali holds 46.06% and PVEP holds 12.5%.

Murphy Oil’s 2009 plans. Murphy Oil predicts that its Malaysian production will increase 72% in 2009 at its Kikeh Field in Block K, which ramped up to a plateau of 115,000 bopd in December 2008 after additional wells were brought onstream last year. Gas production at Block K commenced in December 2008, with the produced gas supplying a third-party methanol plant, according to President and CEO David M. Wood.

At Murphy’s Sarawak natural gas development in Malaysia, Phase 1 gas production is expected to commence in third-quarter 2009 with initial production of 250 MMcfd. The company also plans to drill an exploration well offshore Sabah island this fall.

Cuel to build Muda D platform. Thai engineering company Cuel won its first deal as a main contractor from the Malaysia-Thai joint development area operator Carigali-PTTEP after several jobs as a subcontractor. Cuel was awarded a $2.7 million contract to build the jacket for the Muda D wellhead platform for Block 17 in the Gulf of Thailand. The scope of work includes engineering, procurement, construction, load-out, sea-fastening and onshore commissioning of the jacket, with onshore mechanical completion scheduled for year end.

THAILAND
Canadian operator Pan Orient (60% interest) and Australian partner Carnarvon Petroleum (40% interest) are drilling exploration and appraisal wells in Na Sanun East (NSE) Field onshore Thailand. The NSE-E1 discovery well found oil in 2008 with 2.843 million bbl (gross) of recoverable 2P reserves. The field has several highly faulted volcanic zones, and good results have been obtained so far, Table 1. Oil production is averaging 9,000 bopd, and total concession watercut is about 15%. Well NSE-H3 discovered commercial hydrocarbons on May 27, 2009, in a previously untested, 45-m-thick volcanic reservoir at 610 m of TVD. The well is flowing 32°API oil at a stabilized 840 bopd and less than 0.5% watercut. Well NSE-I1 is drilling ahead, and 10 to 15 additional development, appraisal and exploration wells are planned for 2009, according to Carnarvon CEO Ted Jacobson.

In the nearby L44 license area, Pan Orient and Carnarvon discovered oil with the L44G-D1 well in 2007. In a reserves report dated Dec. 31, 2008, Gaffney, Cline and Associates calculated 125,000 bbl of total proved and probable (1P and 2P) reserves for the prospect. The L44-W exploration well is currently shut in while isolating two volcanic zones.

A 3D seismic survey was acquired over the L44 prospect to better define this structurally complex area. The partners plan to drill a total of eight to 24 exploration, appraisal and development wells in the L44/43 prospect during 2009.

Carnarvon has two other exploration prospects in Thailand: the L20/50 license it operates with 50% partner Sun Resources, and the L52/53 prospect with 50% partner and operator Pearl Oil.

The L20/50 license is on trend with the 200 million-bbl Sirikit oil field, which is producing 20,000 bopd. Seismic data gathered in the 1980s shows many structures in the fractured volcanic zones, and a new seismic survey is planned this summer, with one to four wells to be drilled in 2010.

The L52/53 prospect covers 6,950 sq km and looks to be an onshore extension of an offshore Gulf of Thailand field. There are oil seeps around the basin, and a 2D seismic survey is planned for 2009.

INDONESIA
On April 29, 2009, Indonesia’s Energy and Mineral Resources Ministry awarded 11 new oil and gas blocks to bidders, Table 2. The government initially offered 15 blocks in December 2008. One block did not attract any investors, and the other three had bids that did not meet the government’s technical criteria. The total commitment for the first three years of exploring the 11 blocks was $189 million, and the total signing bonus paid to the government was $21.65 million.

The blocks were offered under a “direct offer mechanism” whereby oil and gas companies may propose to carry out a joint study in blocks of interest. During any subsequent tender process, these companies will get the first priority to develop the blocks.

The contracts were officially signed on May 5, 2009, at the Indonesian Petroleum Association conference in Jakarta. At that event, the government opened a tender for 24 additional new oil and gas blocks. Indonesia hopes to arrest the sharp slide in domestic crude production that forced the country to withdraw from OPEC last year because it was no longer a net oil exporter. The nation’s crude production dropped to 832,200 bopd in March, compared with 844,300 bopd in February and down from 1.5 million bopd in the 1990s. Indonesia has set the 2009 oil production goal at 960,000 bopd.

New rules for cost recovery. The Indonesian government has crafted new rules that redefine some cost components as downstream rather than upstream. Oil and gas contractors used to be able to reclaim expenses on certain upstream activities from the government after the start of production.

For example, LNG export terminals and gas transmission pipelines will be considered downstream components and thus will no longer be deductible as upstream expenditures. These new regulations are being “synchronized” with other legislation, including tax laws.

“We hope that this will decrease spending on cost recovery in our state budget,” Indonesia’s Energy and Mineral Resources Minister Purnomo Yusgiantoro said of the new rules, which are intended to improve transparency and make the program less prone to abuse and graft.

Last year the government paid oil and gas contractors nearly $9.35 billion under the old rules, up from the $8.7 billion paid out in 2007. Indonesia’s House of Representatives agreed to cap cost recovery spending at $12 billion this year, largely by redefining upstream costs as downstream.

Natuna role offered to Petronas. Indonesia has offered Malaysian state energy firm Petronas a chance to participate in developing the giant Natuna D-Alpha gas field, according to Malaysian Prime Minister Najib Razak. The Indonesian government appointed its own state oil firm, Pertamina, as the operator of Natuna, but it does not have the technical expertise—or the $40 billion required—to develop the field alone. The 70% carbon dioxide content of the Natuna gas makes it difficult and expensive to recover and process.

Pertamina wants to keep a 40% stake in the Natuna D-Alpha gas project with 60% to be shared among the partners, which in addition to Petronas could include ExxonMobil, Chevron, Total, Royal Dutch Shell, StatoilHydro, Eni and China National Petroleum Corp. Indonesia had cut off talks with ExxonMobil, which has controlled the block since the 1990s, due to disagreements over how to split the gas produced. Indonesia claims that ExxonMobil’s contract giving it a 76% share has expired, whereas the energy major claims the contract is still valid.

The Natuna D-Alpha block, located 1,100 km north of Jakarta and 200 km east of the West Natuna fields, contains about 222 Tcf of gas, of which about 46 Tcf is deemed commercially recoverable. Pertamina expects the giant gas project to come onstream by 2017—if it gets government approval next year.

On May 6, 2009, Minister Yusgiantoro said that gas from the Natuna D-Alpha block would supply a new LNG receiving terminal to be built by a consortium of three state-owned enterprises: PT Pertamina, PT Perusahaan Listrik Negara (PLN) and PT Perusahaan Gas Negara. The floating LNG storage facility off the coast of Jakarta will have a 3 million-metric-ton capacity and will feed PLN’s Muara Karang power plant and the new Tanjung Priok plant.

Kambuna to begin gas production. In Kambuna Field offshore north Sumatra, operated by Serica Energy, the offshore platform topsides were successfully installed in May 2009, and offshore hookup and commissioning are in progress. Development wells have been completed and tested at 114 MMcfd, and the 58 km of 35-cm pipeline exporting condensate and gas from the production platform to shore has been laid and tested. Construction of the onshore gas reception facility is nearing completion, gas contracts have been finalized, and as of this writing first gas was scheduled around mid-2009.

Consultants at RPS Energy recently upgraded Kambuna’s gross proved and probable reserves to 133 Bcf of sales gas and 11.6 million bbl of condensate, with an upside gross 1P/2P total of 62.5 million boe. Serica holds 50% interest in Kambuna after selling 15% to partner Salamander Energy, which already owned a 35% interest.

Lundin discovers oil near Walio Field. Lundin Petroleum made a significant Kais Limestone oil discovery in April next to the mature Walio Field in the Salawati Basin offshore Indonesia. Lundin holds 25.936% interest, while operator PetroChina holds 30%, Pearl Oil has 34% and Pertamina holds 10% interest in the South East Walio discovery.

Net unrisked contingent resources total 3 million boe, according to Lundin President and CEO C. Ashley Heppenstall, and the field is close to existing infrastructure. Two cased-hole drillstem tests produced 2,300 bopd and 2,400 bopd, respectively, and production was brought onstream at a gross rate of more than 1,000 bopd. Two more appraisal wells are planned in 2009.

CHINA
China National Offshore Oil Corp. is offering 17 oil and gas blocks in the South China Sea to foreign oil companies for bids. The exploration blocks cover 42,021 sq km and include 13 blocks in the eastern part of the sea that had been offered last year and four new blocks in the western sector. Water depths in these blocks range from 18 m to 300 m. CNOOC holds the right to take a 51% stake in the event of a commercial discovery.

Fig. 2. COSL successfully completed a full-scale trial of its Atlantis artificial seabed system in the South China Sea. The concept is designed to allow semisubmersibles to drill deeper waters than usual.

China Oilfield Services Ltd. (COSL) announced that a full-scale trial of its Atlantis artificial seabed system was successfully completed on April 27, 2009, on the continental shelf in the South China Sea. The Atlantis concept comprises a large buoy positioned 200–400 m below sea level that acts as an artificial seabed, Fig. 2. The wellhead and blowout preventer are located on the buoy, which is anchored to the seabed by means of a tieback casing, and no equipment remains on the seafloor. The system is designed for use with semisubmersible drilling rigs, enabling them to operate in much deeper waters, as opposed to having to wait for more expensive drilling rigs to become available.

The technology is patented by Atlantis Deepwater Orient Ltd., a joint venture of COSL and the Norwegian company Atlantis Deepwater Technology Holding AS. The system was deployed under the Nanhai V semisubmersible drilling rig owned and operated by COSL.

PAPUA NEW GUINEA
InterOil Corp. owns 100% of three exploration licenses—PPL 236, 237 and 238—in the onshore East Papuan Basin, and 15% equity in PPL 244 in the Gulf of Papua. Four wells drilled since 2006 in the Elk prospect in PPL 238 resulted in a significant gas/condensate discovery. Both the Elk-1 and Elk-4 wells flowed gas at over 100 MMcfd, establishing Papua New Guinea (PNG) record flowrates.

Fig. 3. Map showing Interoil assets in Papua New Guinea.