Far East

Exploration and development encouraged

As the many countries modernize, increasing energy demand creates markets for both domestic production and imports. Foreign help is wanted

Tony Sitathan, Contributing Editor (Indonesia, Malaysia, Thailand and Vietnam)

China. The three largest Chinese firms – CNPC (PetroChina), Sinopec and CNOOC – control most oil/gas operations, operating principally in the north and west, the south and east and offshore, respectively. CNPC / PetroChina control more than two-thirds of the country’s oil/gas production and pipelines, including about 90% of the oil production located onshore. Estimated oil production in 2001 averaged 3.2 MMbopd, with net imports of 1.6 MMbopd. Three onshore fields, Daqing, Shengli and Liaohe, in the Northeast, contributed 1.1, 0.5 and 0.3 MMbopd each. Gas production is 2,400 MMcfd, with most undeveloped reserves in the isolated West. The country drills about 10,000 wells a year, principally around known developed onshore fields, with some 900 exploration / appraisals. Offshore exploration totals 50 – 60 wells (2002) with CNOOC contributing about 40%, foreign operators the rest.

The biggest onshore gas discovery is the Sulige field in Ordos basin in the Inner Mongolia Autonomous Region. The field reportedly contains more than 16 Tcf and could contribute to the huge West to East, 4,200-km gas pipeline from Western Xinjiang to Shanghai – which is still being organized, with Shell now as the lead project firm. Other oil/gas pipelines are also under consideration. Three onshore discoveries by PetroChina in Tarim basin in 2001 were considered significant by Wood Mackenzie, Ake-1 (gas), Quele-1 (oil/ gas) and Lungu-15 (oil).

Offshore activity is generating news because foreign operators are involved with CNOOC in four offshore areas: Bohai Gulf, South China Sea, Beibu Gulf and East China Sea. Significant exploration wells drilled in 2001 and early 2002 include: for Bohai, 14 wells by Kerr McGee in Caofedian, (Blocks 4/36, 5/36); two by ChevronTexaco, Bozhong 25-1-4, (B 11/19) and LD 27-2-2, (B 2/31); one by Agip, CFD 8-5-1, (B 2/31); one by Agip, CFD 8-5-1, (B 9/11); one by Apache, Zhao Dong B-1, (B 9/11); one by EDC, CB-1, (Chendaoxi B); and one by CNOOC in Nanbao 35-2-7, (Bozong).

In the South China Sea, the CACT consortium drilled two wells: Huizhou 19-2-1, 19-3-2, (B 16/19); Devon, three: Huizhou 9-2-1, (B 16/02), Wenchang 6-1E-1, (B 26/35) and Panyu 6-4-1, (B 15/34); Burlington, one: Huizhou 29-1-1, (B 16/21); ACT, one: Huizhou 19-1-1, (B 16/19); and CNOOC, three: Baodao 15-3-1, Liuhua 19-3-1, and Wenchang 15-1-1. In Beibu, CNOOC drilled the Weizhou 12-1-6 appraisal; and in the East China Sea, Primeline drilled the Lishi 36-1-3 appraisal. Of the 34 wildcats / appraisals noted, eight were dry holes.

Notable offshore developments underway include, in Bohai: ChevronTexaco’s Qinhuangdao 32-6 (oil) using the FPSO Bohai Shi Ji; and CNOOC’s initial flow from Platform C (the third of six) on Suizhong 36-1, Phase II. Phillips’ Peng Lai 19-3, China’s largest offshore oil field, Phase I, was to start in 2002; Phase II with a newbuild FPSO is slated for 2006. In the South China Sea, CNOOC / Husky are using the FPSO Nanhai Endeavor to produce Wenchang 13-1/13/2 oil fields in Blocks 31/32. CNOOC is also developing Dongfang 1-1, a gas field west of Hainan Island, to be the second largest offshore gas field after Yacheng 13-1; facilities are planned on Hainan for 2003 startup. And in early 2002, Devon contracted with Kvaerner for a newbuild FPSO to service Panyu 4-2 and 5-1 wellhead platforms, by 2003.

In two other offshore areas, CNOOC says development of the Xihu Trough in the East China Sea, in partnership with Sinopec, has begun. The area, 280 mi SE of Shanghai, includes several oil/gas fields. And plans are being resumed for cooperative exploration of the Taiwan Strait, to involve CNOOC and Taiwan’s CPC.

Oil and gas production were both lower last year in Indonesia. However, Gulf Indonesia Resources reported that its better-than-expected condensate recovery from gas output partially offset production declines in mature oil fields. (Photo courtesy of Gulf Indonesia Resources)

Indonesia. As a positive step in reforming Indonesia’s petroleum sector, the much-awaited Oil and Gas Bill was passed in October 2001, replacing Laws 44/1960 and 8/1971. The law redefines the role of state-owned Pertamina and assists in deregulating the downstream market.

Indonesia experienced some misses in 2001/2002, with continued evaporation of foreign funds since the heydays of 1997. The number of new PSCs is down, with only five signed in 2000, four last year. There are plans to tender 17 blocks for oil exploration; last year, six blocks were awarded to six companies.

For most of 2001, Indonesia’s net exports averaged 330,000 bpd oil / condensate. Crude / condensate production dropped to 1.4 MMbopd in 2001. LNG exports decreased 11.5% to 23.9 million mt. And gas production declined to 9.2 Bcfd in 2001. Most major producers (Caltex, BP, ExxonMobil, Vico, Gulf Resources and Pertamina) experienced production declines. These were offset by increases from Exspan, Devon and Total Indonesia.

For exploration highlights, ChevronTexaco announced a $15-million program in North Sumatra. Caltex Pacifix intends to explore a 4,300 km² area in Labuhan Batu regency. Gulf Indonesia Resources intends to tap Jenggolo-1 oil/gas field and Payang-1 gas discovery in the Ketapang PSC, offshore East Java; appraisal drillings are likely. Eni has appraised its three discoveries in offshore Eastern Borneo – in Ranggas, Gendalo and Gandgang – total reserves could exceed 800 MMbbl oil. And Exspan and Pertamina discovered a large, 5-Tcf gas reserve in Luwuk Banggal regency in South Sulawesi.

Developments progressed with Pertamina and Bumi Siak Pusako to maintain oil output at a field in Riau province by drilling five wells to maintain 40,000 bpd, after taking over operations from PT Caltex Pacific Indonesia. Pertamina intends to build two liquefied gas lines with PT Medco Energy International, after doubling their gas reserves in the Central Sulawesi fields. Reserves in Senoro-Toili block rose to 9.3 Tcf. Six million tons of LNG / year are planned. The Clough Group won a bid for the first deepwater oil production field in West Seno in the Makassar Straits.

Unocal’s Indonesian subsidiary, Unocal Rapak, drilled its fifth successive well on the deepwater Ranggas oil field, testing 8,158 bopd, plus gas. Unocal intends to spend up to $3 billion developing fields in Indonesia within several years to increase its output. It found as much as 1.3 Bbbl oil after drilling more than 100 wells from 1998 to 2001 off East Kalimantan, and is considered the world’s top LNG exporter. It is building on gas discoveries in the Gendalo-Gandang complex offshore East Kalimantan, with estimated production in excess of 90 MMcfd gas and 6,000 bpd condensate. And Premier Oil intends to raise oil/gas production by 20% this year with developments.

India. The principal upstream operator in India is state-owned Oil and Natural Gas Commission (ONGC). The smaller Oil India Ltd. (OIL) operates mainly onshore. ONGC supplies more than 80% of the domestic output and operates most E&P activities, including offshore. Domestic oil production is only 587,000 bpd, and the country consumes 1.9 MMbpd, requiring net imports of 1.3 MMbpd. Natural gas use is projected to increase to 1.3 Tcf/yr by 2005. LNG import projects are underway, plus proposals for import pipelines.

India has had programs to entice foreign upstream participation for several years. The largest new program is the New Exploration Licensing Policy (NELP) launched in 1999, with marketing of 48 onshore / offshore blocks; 24 were awarded in early 2001. NELP II closed for bidding March 2001; 23 onshore, shallow / deep offshore bid awards included: 16 for ONGC; Reliance / HEPI four; and one each to Oil India, GSPCL consortium and Niko, the only foreign operator. NELP III was to be announced in early 2002, to include more deepwater blocks. India’s first coalbed methane licensing round was announced in December 2001.

Exploration drilling as reported by Wood Mackenzie has been dominated by Cairn’s offshore efforts in 2001 in deepwater (1,100 m) Block KG-DWN-98/2 in Krishna-Godavari basin off the East Coast. Five wells were drilled, confirming Annapurna gas field, following the N-Cluster and the P-Discovery. Another wildcat, DWN-M-1ST-1 found oil/gas in the M-Discovery. One Cairn well onshore in Rajasthan found oil and gas.

Essar also found oil with the first well in unexplored RJ-ON-90/5 block near the Pakistan border. And in Cambay basin, 20 – 30 mi offshore Gujarat, Niko-operated Hasira A-1 confirmed additional oil/gas in the discovery, just east of Cairn’s Lakshimi gas field, which will see first production in mid-2002, with two wellhead jackets linked to the export line. In early 2002, Tullow was planning wildcat GK-OSJ offshore near Pakistan; and Essar was to spud BB-0S/5 off the West Coast in Gujarat Kutch basin. Cairn drilled two more wells in Krishna Godavari in early 2002 and pursued offshore field developments in the area with possible scenarios to tie G-2, Q, N, M and Annapurna deepwater discoveries into the Ravva complex.

Bombay High field is the leading producer with its 200,000 bpd output, nearly 40% of the country’s total. A major goal is to boost reservoir recoveries in other fields using vital foreign technology investment – ONGC seeks to improve 14 major fields by stages. It is also launching Phase II of Bombay High redevelopment, covering the southern area. The $1 billion program, to have started in mid-2001, will boost recovery 5%. Elimination of wasteful gas flaring is a major objective.

Malaysia. For 2002, Malaysia has forecast crude production of 690,000 bpd, from 42 fields. Malaysia has adopted a more pro-active role for new ventures in international areas. The government says its 4.5 Bbbl crude reserve could be drained within 14 years. Petronas has invested in exploration / production in 12 countries.

For exploration, oil and gas fields are almost entirely offshore, either Sarawak or Peninsular Malaysia. Major producing fields include Baram, Baronia and Tukau (all Petronas / Shell), Seligi and Guntong (Petronas / Esso) and Duland (Petronas). Over half the country’s production comes from Tapis field. BP Malaysia plans to double its investment by 2010. Royal Dutch Shell will invest $5.3 billion in oil and gas projects in Malaysia over the next five years.

Drilling and production activity will increase 2002 oil production by 2.4%, while gas production is forecast to climb by 11.4%. Wells in Peninsular Malaysia will account for 60% of the total crude oil production; Sarawak, 25% and Sabah 15%. Gas reserves are 82.5 Tcf (the world’s twelfth largest). Gas demand is rising rapidly, and is expected to increase 7.6% to 1.71 Bcfd this year. Malaysia is expected to produce over 6.0 Bcfd in 2002.

Esso Production Malaysia Inc. (EPMI) was the largest crude producer in Peninsular Malaysia, accounting for nearly half of the country’s production. EPMI operates seven fields near the Peninsula, and one-third of its production comes from Seligi field. The Seligi-F platform, with its 28 wells, is the newest satellite in Seligi, 165 mi off Terengganu.

ExxonMobil Exploration & Production Malaysia Inc. (EMEPMI) and Petronas Carigali Sdn Bhd (PCSB) have initiated gas production from Angsi field and an integrated five-satellite field project. The five-platform Satellite Fields Development (SFD), operated by (EMEPMI), is the first oil/gas facility development of its kind in Malaysia. The Seligi H satellite platform was installed along with four sister satellite platforms: Raya B, Lawang A, Serudon A and Irong Barat B. At its peak, Seligi H will produce 11,000 bopd and 29 MMcfd.

Larut, the latest major oil/gas platform development operated by EMEPMI, is scheduled to come onstream this year. EMEPMI has a 50/50 share with PCSB in Larut, 125 mi off the coast of Terengganu. And MLNG Tiga, a joint venture of Petronas, the Sarawak state government, Nippon Oil and Shell Gas, has plans to open two existing LNG facilities. The plant will boost Malaysia’s total LNG production to 23 million tonnes / year and transform Bintulu into the world’s largest LNG production site.

In the Malaysia-Thailand Joint Development Area (MTJDA), Trans-Thai Malaysia Co., a JV between Petronas and the Petroleum Authority of Thailand (PTT), intends to finally construct a $465-million, 227-mi, gas pipeline between the two countries after a two-year delay. The project allows large potential gas reserves to be tapped from an offshore field in the Gulf of Thailand where it has a capacity of supplying 1.0 Bcfd. Malaysia intends to buy all the gas for the first five years. The delays were caused by Thai villagers and environmental groups.

Onshore Thailand, Pacific Tiger Energy's WB-N2 appraisal confirmed the Wichian Buri North discovery last year. The firm and its partner, Carnarvon Petroleum, are conducting a three-phase development drilling program at the field this year. (Photo courtesy of Pacific Tiger Energy Inc.)

Thailand. The economy is on its road of recovery. And to help, efforts are underway to restructure / privatize Thai petroleum and electric utility company organizations.

For drilling and development, Chevron Thailand has kept up its record-producing 40,000 bopd and is considered the top oil producer; total gas production has doubled to its main customer the Petroleum Authority of Thailand (PTT). There has been further interest in exploiting Block B8/32, along with interest in North Jarmjuree Block, an offshore area covering 1,200 sq mi over the Gulf of Thailand; the latter to come online by 2004. Beyond Petroleum intends to retain its stake in a gas project in the Gulf of Thailand after failing to sell the asset this year. It wanted to sell 25% in the field that will supply gas via a $735-million pipeline. Petronas and PTTEP each own half of two gas fields that will supply the pipeline. The company has declined bids from private and Asian national oil companies. Gas production would commence in 2005; PTT intends to buy half the output.

Regarding production, Thailand produced 114,000 bpd of crude / condensate in 2001. Oil reserves have improved to over 580 MMbbl due to significant discoveries. And it has 13.3 Tcf gas reserves; most in Bongkot gas field in the Gulf of Thailand. Unocal Thailand is the largest gas producer, and it has discovered new reserves in Pailin and Trat fields. It intends to resume a second phase development at Pailin in mid-2002 and raise production to 330 MMcfd. Chevron produces 145 MMcfd from its offshore Block B8/32 and plans to increase it to above 250 MMcfd. It says estimated reserves stand at 2.5 Tcf. PTT Exploration and Production Public Co. Ltd. (PTTEP) is involved in 17 JVs, and has accounted for a significant percentage of domestic supply.

Vietnam. With normalization of relations with the U.S. in 2001, Vietnam has steadily increased imports of U.S. equipment, as well as much-sought-after technical expertise for its oil/gas industry. There has been progress and development in its oil/gas industry although its per-capita energy consumption is one of the world’s lowest. Its oil ally Russia tentatively plans to produce at least 280,000 bopd until 2006. The JV between Russia and Vietnam, Vietsovpetro (VSP) remains Vietnam’s biggest producer, accounting for some four-fifths of the total oil output.

For exploration, Thailand’s PTT Exploration and Production Public Co. (PTTEP), has plans to participate with SOCO Vietnam, and explore two offshore projects – Blocks 9-2 and 16-1 – off the coast of Vung Tau. Block 9-2 covers 1,370 km²; 16-1, 3,350 km². Delek Energy Services from Isreal has discovered gas off the coast of Southern Vietnam which could yield up to 20 MMcfd. Opeco, from the U.S., has hit gas in 2,200-km² Block 12 W in Nam Con Son basin. Noble Affiliates has a discovery with the 12-W-TX-1X well in the Swan prospect, offshore Nam Con Son basin that tested 20 MMcfd gas and 150 bpd condensate. The three national oil companies PetroVietnam, Petronas Carigali (Malaysia) and Pertamina (Indonesia) have formed a JV to explore / co-develop oil / gas in two offshore areas, Blocks 10 and 11.1, in Nam Con Son basin; drilling is expected in mid-2003.

Development and drilling activity includes plans by Russia and Vietnam to expand on the joint cooperation between Russia’s Zarubezhneft and PetroVietnam to construct a refinery in Vietnam, for completion in late 2004. PetroVietnam’s Petroleum Technical Services Co. (PTSC) and McDermott have a contract for a wellhead platform for the Su Tu Den (Black Lion) oil project off SE Vietnam. PetroVietnam is seeking partners to jointly develop the Song Hong basin offshore North Vietnam. The basin covers almost the whole Gulf of Tonkin, with 100,000 km², and has reported 9 Tcf recoverable gas, 13 Tcf in place.

Beyond Petroleum has already started supplying gas discovered in Blocks 06-1 to Phu My City from Lan Tay and Lan Do offshore fields in the southern Nam Con Son basin. The fields have total reserves of 2 Tcf. PetroVietnam Drilling and Well Services Co. (PV Drilling), a spin off from PTSC, intend to enter the drilling game with construction of their first jackup, for $100 million, to operate in water depths to 90 m. This unit comes from Singapore-based Keppel Fels. It will be used in Cuu Long and Nam Con Son basins.

Vietnam’s oil production has dipped in recent months. Data shows that for five months, oil production dropped to 329,000 bpd in May after averaging 335,000 bopd for four months. The country is still a net oil products importer, although there are plans to build an oil refinery. KNOC intends to ink a deal with PetroVietnam to receive up to 140 MMcfd gas from Rong Doi field in Block 11-2; reserves are 1.2 Tcf; production would come onstream by 2005. In terms of potential recoverable gas, Vietnam claims 23 Tcf in four basins. All the gas is planned for the domestic market. Unofficial proven reserves are in the 7 Tcf range.

Pakistan. The state oil company, Oil & Gas Development Corp., is now a limited company known as OGDCL. Two other domestic companies are Pakistan Oilfields Ltd. (POL) and Pakistan Petroleum Ltd. (PPL). The country is divided into four areas, Sindh (Southeast), Punjab (Northeast), Balochistan (Southwest) and the North West Frontier Province. These encompass three geologic basins, Lower, Middle and Upper Indus (LI, MI & UI). Only a few offshore wells have been drilled. In 2001, oil output was 60,000 bopd, including condensate; net oil imports in 1999 were 302,000 bopd; reserves are about 300 MMbbl. The natural gas picture is brighter, with reserves in the 24 Tcf range and production meeting consumption at 2,400 MMcfd. New field developments should meet growing gas needs for several years, delaying proposals for imports via pipelines.

The government increased license periods to five years from three. Increased activity in offshore Makran basin and isolated Balochistan is hoped for. The target is 100 exploration wells per year. New awards in 2001 include: Orient, B3370-5, Karak (UI); Tullow (Devel.) Suri (LI) and Sara West (LI); Hycarbex, B2768-7, Balochistan; POGC, B2869-10, MI; Pakistan Petroleum, B3371-7, UI; BP (Devel.), Junathi South, LI; OMV (Devel.), Sawan, Sindh; and OGDCL (Devel.), Pali, Sindh.

Exploration drilling highlights, as reported by Wood Mackenzie, mid-late 2001 through early 2002, include: Agip (1 well) Kirthar LI; OGDCL (5) Uch MI, Hala LI, Basal UI, Boski UI, Bokharar MI and Sinjoro LI; Mari Gas (4), Mari MI; Petronas Carigali (2), Mubarik MI; MOL (1), Tal UI; Ocean Energy, offshore Makran, late 2002; OPI (2) Mirphur Khas LI; PEL, Kandra MI; PPL, Block 22 MI; and Premier, Bolan MI.

Gas developments are the main goal. In 2000, the government prepared a two-phase program to address Hassan, Zamzama, Miano, Sawan and Bhit through 2002; and add Mari Deep and Sui Deep by mid-2003. Other developments noted include PPL’s Mazarani; Tullow’s Charchar; plus Zarghan and Badhra. These efforts could increase gas output to 3,500 – 3,700 MMcfd by 2003, with declines thereafter. These efforts essentially meet domestic needs for a while, putting three optional proposals for gas imports by pipeline on the back burner, including the Iran-Pakistan-India line; a line from Turkmenistan through Afghanistan; and linking Pakistan to the Dolphin project which supplies gas from Qatar to UAE and Oman.

Myanmar. The state oil company Myanma Oil and Gas Enterprise (MOGE) drills 40 – 50 onshore wells a year. The country imports most of its oil needs and produced about 14,000 bpd crude / condensate, plus 840 MMcfd gas, in 2001. There are two major gas fields offshore in the Andaman Sea, TotalFinaElf’s Yadana, 100 mi SW of Yangon, and Premier’s Yetagun, 170 mi SE of Yadana. Both fields pipe gas to the southern coast, with a marketing line on to the Bangkok area in Thailand. Yadana will also supply domestic Myanmar when a line is built to the coast.

In 2001, CNPC of China acquired 70% of Bagan onshore blocks from TG World of Canada to increase reserves. South Korea’s Daewoo International sold 10% in Block A-1 in Arakan offshore to Korea Gas Corp. And in 2002, Daewoo sold 30% of Block A-1 to India’s ONGC and Gas Authority of India. The block holds significant gas reserves and drilling will start in 2003; a pipeline to East India could be considered. And in December 2001, MOGE /CNPC signed an Improved Oil Recovery contract (IOR-4) for onshore Pyay field, Central Myanmar; 3-D seismic and further drilling are planned. In mid-2001, Focus Energy drilled Peppi 17 and 18 exploration gas wells in Htaukshabin PCC onshore.

Brunei. This small country has relatively large reserves of 1.2 Bbbl oilcondensate and 8.5 Tcf gas. It produces over 190,000 bopd, plus 1.2 Bcfd gas, 90% from Brunei Shell Petroleum (BSP), in 50% partnership with the government, including the 7.2 MMmt/yr Lumut LNG plant. BSP’s production comes mostly from West Ampa, Champion and Seria fields in shallow offshore water.

In late 2001, the government offered two deepwater offshore blocks and one shallow water / onshore block. By early 2002, TotalFinaElf had been awarded Block J, 5,000 km², 60 mi offshore in 4,000 – 6,000-ft water; and Mitsubishi / Shell / Conoco reportedly signed for Block K, 50 mi offshore. The government formed a new company called National Oil Co. to "help develop a domestic industrial base and participate in E&P." And BSP announced 2002 development of the new offshore Egret oil/gas field. First gas from Phase 1 may be onstream by late 2003, with Phase 2 oil development by 2006. A 12-slot platform in 200-ft water and a multi-phase pipeline will be built by Technip-Coflexip.

Philippines. The biggest news in 2001 was inauguration of Shell Philippines Exploration’s Malampaya deepwater development in 2,800-ft water, 40 mi NW of Palawan. On September 27, first gas flowed through the 312-mi long pipeline to the first of three power plants at Batangas on the mainland. An $80-million pipeline from Batangas to Manila is being considered. Some 400 MMcfd is expected by 2003. Condensate is exported via a 24-in. line to a CALM buoy for shuttle tanker transport. Five subsea wells have been drilled. By April 2002, Shell had drilled the MA-10 oil appraisal on the oil rim of Malampaya. Shell and partners Texaco Philippines and Phillipine National Oil Co. expect oil production of 35,000 – 50,000 bopd. An FPSO development plan is expected with first oil by 2004.

Other exploration efforts in the Malampayan basin have been paced by Nido Petroleum in its Coron North prospect in SC-42, next to SC-38 (Malampaya). Trans-Asia has drilled the San Isidro well in East Visayan basin. And PNOC plans to drill in Lagao, Lambayong province. These efforts portend a bright near future for oil development. The government wants to continue development of proven smaller gas discoveries, including Libertad field in Cebu. Oil production from the country increased to 2,135 bopd in 2001, with added offshore Malampaya liquids at 20,000 bpd late in the year. Gas output increased to nearly 14.0 MMcfd from 1.0 MMcfd in 2000. This will increase rapidly with Malampaya’s developing market.

Others. The Far East contains several other countries with production and active oil/gas exploration efforts, but no large projects reported; these include: Afghanistan, South Korea, Cambodia, Bangladesh, Japan, Taiwan and Mongolia. Other countries reported essentially no current oil/gas activity.