INDONESIA - Central Sumatra - Oil & Gas Fields.

Caltex Pacific Indonesia (CPI) is the local unit of Caltex which in October 2001 was renamed ChevronTaxaco Asia, Middle East, Africa Refining and Marketing (ChevronTexaco AMEA). But the Indonesian unit's original name, CPI, has remained. CPI operates the main oil province under the jungles of Central Sumatra. Caltex, created as a 50-50 Chevron-Texaco company operating in various parts of the world with emphasis on Asia, is now fully owned by Chevron which has taken over Texaco. Indonesia is its main oil production zone.

CPI's onshore area is within the Riau Province, where its production now averages about 550,000 b/d, down from 660,000 b/d in early 2001 and 750,000 b/d in early 1999, and still accounts for almost half of Indonesia's total oil output. Its main PSC has been renewed until 2021. In late 1996, CPI got better tax terms from the state, whereby it was allowed to charge interest on loans associated with its oil producing fields and EOR system as an operating cost. As a result, CPI decided to boost its production in 1997 to 785,000 b/d, from 760,000 b/d in 1996, and to raise spending that year to $400m. But production in 1998 and 1999 fell below that target. It has fallen and its E&P spending has been cut since 2000.

CPI Managing Director Chris Prattini said in Sept. 2002 his firm intended to raise output at its Duri field to compensate for expected falls else-where in the province. CPI is expanding the steamflood system at Duri that should boost output in 2003 from 23,000 b/d. Output at its Minas field is to remain at 120,000 b/d for the near future. CPI President Humayunbosha said: "Reserves in the Minas field are still large. We are still studying chemical injection system for Minas but this requires about three years and big investment". He said CPI's output would average 550,000 b/d in 2003 because of natural declines and loss of the Central Plains Pekanbaru (CPP) production sharing contract.

CPI in Aug. 2002 had to transfer CPP to a JV of Pertamina and the local Riau government called Bumi Siak Pusako (BSP). But the JV lacked the expertise or funds to maintain CPP's EOR system which the former operator used. Output in the CPP block has fallen from 50,000 b/d to 35,000 b/d. Theft of equipment and sporadic disputes have hampered CPP operations. At one time in Aug. output fell to 6,000 b/d. BSP, which took over the CPP block on Aug.9 after CPI had spent 31 years at the helm, said production had fallen due to frequent power supply interruptions. CPI said brownouts were commonplace in Indonesia. CPI said it was continuing to supply power to the CPP block, although it was no longer involved there, adding: "BSP's complaint is actually the result of a common happening. Power outages are being experienced by our own installations".

In 1996, Caltex had re-organised its Asia-Pacific operations after it withdrew from Japan. In March 1997 it adopted a new strategy to reduce costs and raise profitability. In its global system, the refining, terminal and trading units stopped offering the group preferential prices; they invoiced affiliates with the best price possible. The change affected CPI (see background in Vol. 56, No. 10). In the autumn of 2002 a labour dispute between management and workers at one of CPI's major contractors, Tripatra, caused activities at CPI's offices in Riau to stop in Sept. as about 4,000 of Tripatra workers demonstrated to demand higher severance pay. They blocked roads leading to CPI offices in Pekanbaru and Duri, which stopped staff from reaching their work place. (The dispute was related to a $686m 1983-2003 contract awarded to Tripatra, which included engineering, construction and operation and maintenance work at CPI's facilities. A total of 250m manhours were required under the contract, Tripatra noted. But CPI wanted to scale back these services, with Tripatra also having a separate $50m three-year contract for work at the Duri steamflood project area II. About 1,200 out of the 3,700 affected Tripatra employees had accepted an offer of planned lay-offs in April 2002. The protesters, though, demanded CPI be held responsible for the fate of the workers that Tripatra was to retire).

Eventually, the problem was resolved after CPI paid compensation and the striking workers returned equipment which they had taken and left the company's premises. CPI's first major oilfield, Duri, was found in 1941 and put on stream in 1958. Its bigger giant, Minas, was discovered in 1944 and came on stream in the 1950s as well. More than 100 smaller oilfields have been discovered in this area and put into production. At their peak in 1973, these fields' production averaged nearly 1m b/d. CPI has also found small gas fields, from which the output serves its production system and EOR units in the oilfields. Most of the hydrocarbons in CPI's area are reservoired in deltaic sandstones contained in anticlinal structures.

Minas, the largest field in Asia with oil in place exceeding 4 bn barrels, was found at a depth of 2,600 ft. Its export crude oil, known as Minas or Sumatran Light, is 35 deg. API with 0.1% sulphur, suitable for direct burning by power plants in Japan and other markets. The crude is exported from the Dumai terminal together with the other CPI crudes. Minas oil is waxy. Its recovery is difficult. CPI has invested on EOR, including a $400m steam flooding system installed in 1995 serving the field's 13 zones.

Duri near Minas, a shall oilfield found at a depth of 770yft, produces a highly viscous oil, 21.2 deg. API, which cannot be pumped by conventional means. Resting in fine sand, it is like honey taken out of a refrigerator and will not pour easily until it warms up. Thus, it is the site of the world's most expensive steamflood project on which CPI has spent heavily.

The flood project, with high-pressure steam pumped into the field's wells, covers 6,600 hectares (16,309 acres). It involves 400 steam generators and 4,445 new wells (in addition to the 725 old wells) - 1,270 wells for injecting the steam and 3,175 for extracting the oil - plus 2,000 miles of pipelines connecting the wells and processing plants. The field is divided into hexagonal patterns with one steam-injection well placed inside a ring of production wells. The system floods the wells continuously with steam to make the oil flow to the surrounding wells. CPI had experimented with gas injection and various other types of EOR, including water injection, before starting the steamflood system in 1984. By then, Duri's unassisted production had fallen below 30,000 b/d compared to 65,000 b/d in 1965.

High-pressure steam is generated by electricity from natural gas. The field's total capacity, including production by primary means, rose to almost 325,000 b/d - a peak reached in late 1994 - but now this and other fields in the area produce 260,000 b/d, compared to 300,000 b/d in early 1999. Output includes oil produced at a nearby offshore field (see below).

The production cost at Duri is averaging about $8-8.50/b, down 50 cents/b from early 1995, thanks to the use of gas for the EOR system. The cost of producing from the other CPI fields is averaging about $3-5/b.

CPI buys the gas from a consortium led by a Gulf Indonesia (a Canada unit of ConocoPhillips) operating Corridor Block (Grissik) in South Sumatra. The gas, coming by a 300 MCF/d pipeline from Grissik on stream since late 1998, has replaced 50,000 b/d of crude oil which used to be burned for Duri's EOR system. The gas volume was raised to 390 MCF/d in 2002 and will reach 480 MCF/d from mid-2003, under a 20-year agreement signed in late 2000, with Gulf getting paid in Duri crude. Increased gas deliveries will help CPI boost the recovery rate at Duri, whose full potential has been put at 6.5 bn barrels. To tap this reserve until the field is abandoned later on in this century, total investment would probably reach $40 bn.

CPI operates the nearby offshore Rokan Block, under a separate PSC, where a small oilfield was found in early 1996. The first well, 35 km north-west of Minas, reached 5,010 ft (1,503 metres) and tested 702 b/d of oil. The second well, closer to Duri, reached 5,159 ft and measured 496 b/d, with Pertamina saying on Feb. 27, 1996: "This well is a significant stratigraphic test discovery which could open up new exploratory potential along the western flank of Duri field". Oil produced from this block is part of the Duri stream.

CPI is operating five blocks in Riau province: the onshore Siak and MFL tracts, and the offshore Nias, Rokan and Sibolgan blocks. Nias is off West Sumatra and is still being explored. Sibolgan is off North-West Sumatra just north of Nias. Both Sibolgan and Nias are gas-prone areas. After discovery and development, the gas from these blocks would be supplied to the Duri EOR system. The PSC for Sibolgan was signed in mid-1996. (See background of CPI's operations in Vol. 56, No. 10).

Santos, an independent Australian firm, operates the adjacent gas/condensate-rich PSC blocks of Bentu and Korinci-Baru south-east of Riau's capital Pekanbaru in Central Sumatra. Their three fields, Bentu, Segat and Seng, are being developed. The Bentu gas system is to produce 120 MCF/d from 2005 and the gas will be supplied to CPI for the latter's steamflood project at the Minas oilfield under a long-term contract.

The three fields, rich in very dry gas, are 45 km south-east of Minas. The existing Duri-bound pipeline of state-owned gas transmission company, Perusahaan Gas Negara (PGN), crosses the two blocks. Santos in 1998 took over the Bentu block from Apache Corp. of US which confirmed the Bentu discovery in 1993. The US firm discovered Seng in late September 1994 (see background in Vol. 56, Gas Market Trends No. 10). Santos operates gas-rich offshore blocks east of Java (see below).

North Sumatra/Aceh - ExxonMobil & Arun LNG: The Dec. 9, 2002 accord signed in Geneva by the government and the rebel Free Aceh Movement (GAM) aimed at ending two decades of war in this Northern Sumatra province. It called for a ceasefire to be monitored by GAM, Jakarta and foreign representatives, a new regional autonomy law giving the oil- and gas-rich Aceh a provincial government with 70% of the net income from its natural resources, and elections. Whether or not the peace deal will hold, on which ExxonMobil depends for its operations in Aceh, remains to be seen (see OMT 9). Exxon Mobil, facing a human rights lawsuit filed in the US by labour activists who contend it is responsible for the misdeeds of soldiers guarding its Aceh operations, is intensely sensitive about its image in the area. In 2001, its Aceh operations including a huge LNG complex run by Pertamina, were shut down for four months from March 9 as a result of increased violence. With Pertamina operating four of the LNG plant's six trains, ExxonMobil's assets in Aceh are now being guarded by 3,000 soldiers.

North Sumatra, including its offshore, is mainly a gas zone, with oil produced primarily from Tertiary clastics in small sized fields. Most of the hydrocarbons in this region are located onshore. But large gas deposits have been found in reefs offshore similar to that of Arun, in Aceh Province which is the northernmost part of Sumatra.

Arun has been one of the world's largest suppliers of LNG, but now it is depleting. It was found in Nov. 1971 by Mobil Oil Indonesia (now part of ExxonMobil), then with more than 14 TCF of gas and 750m barrels of condensates. Its development began in late 1973 after Mobil and Pertamina secured long-term LNG sales contracts with Japanese buyers. The field lies in Mobil's Aceh Block offshore about 20 miles from the Arun LNG terminal and about 150 miles north of Medan, the third largest city in Indonesia. The field covers about 35 sq miles and has had a thickness of 1,100 ft. It is reservoired in a pinnacle limestone reef. To mark its 20th anniversary on Nov. 18, 1991, Mobil raised Arun output to a peak of almost 1,100 MCF/d and more than 120,000 b/d of condensates. Since early 1992 production has declined. The depletion was evident with the fall in Arun's condensate yield, which in 1994 reached 80,000 b/d and fell to less than 50,000 b/d in 2000. The field's gas production could last until 2010.

While Pertamina had a tough stand on Mobil, the state concern had in 1991 signed a contract with Chevron guaranteeing it 40,000 b/d of condensate supply from Arun for 10 years beginning from 1995. Chevron now is using the condensate as a feedstock in its petrochemical plant at Banda Aceh. This deal left the clients of both Mobil and Pertamina with very limited quantities of condensate.

As part of hard bargaining between the US major and Pertamina over the renewal of Mobil's PSCs, as Total had done a few years earlier concerning its East Kalimantan blocks (see below), Mobil in early 1992 began negotiating with Qatar for partnership in large gas developments for LNG export. That followed BP's withdrawal from the Qatargas venture. Mobil was introduced to Qatar's QGPC by Mitsui & Co., and eventually it joined Qatargas and went into a larger LNG venture with QGPC called Rasgas (see LNG survey serialised in 1994 Volumes 42 and 43).

After much bargaining, Mobil's PSC with Pertamina was renewed until 2018. The terms were encouraging enough for the US major to embark on a massive gas exploration programme. By mid-1993, Mobil had made four major gas/condensate discoveries on its Aceh block with recoverable reserves proven at 1.8 TCF. Since then, discoveries have raised the proven reserves there to about 3.5 TCF. The fields are being developed. Two of these, with 2 TCF of reserves, including the Pase A, went on stream in 1998 and the gas has feed the Arun LNG complex. But Pase was shut down for rehabilitation in 2001 and production was restrated on March 4, 2002.

The third field, offshore NSO-A 101 km from Arun, went on stream in mid-1999 and is now producing 450 MCF/d. But NSO-A's gas is not as clean as in the Arun field and other structures. So the operating costs at NSO-A are higher than in the other fields. The gas is being supplied to the LNG complex. NSO-A, found in 1972 by Mobil, lies in 350 metres of water. A 7,000-ton production platform over the field supports output from nine wells and has facilities to cool and dehydrate the gas. The platform is remote-controlled, with personnel visiting it every other day. A 101-km subsea pipeline links the platform to onshore treatment, compression and sulphur-recovery facilities installed at the LNG complex.

Another offshore field, South Lhoksukon, has been developed. Together with the other fields, ExxonMobil now is producing about 1,700 MCF/d, of which 1,300 MCF/d go to the Arun LNG complex and the rest feed fertiliser plants in North Sumatra. In addition, ExxonMobil is producing about 27,000 b/d of condensates, exported in the spot market through Pertamina.

ExxonMobil, with Exxon having acquired Mobil in early 1999, owns 30% of the 13.8m t/y complex, PT Arun NGL, with 55% held by Pertamina and the rest held by Japan-Indonesia LNG Co. (Jilco). Because of Arun field's depletion, two of the complex's six trains were closed in February and March 2000 bringing total operating capacity to 9.8m t/y.

In July 1994, Mobil took a 50% interest from Inpex (Indonesia Petroleum of Japan) in the North Aceh Block, off the northern tip of Sumatra island and adjacent to Mobil's Aceh tract. This is rich in gas and condensates, with its output added to ExxonMobil's production system (see Vol. 56, No. 10).