Indonesia Oil & Gas Fields - The Timor Gap.

The eastern half of Timor island and the potentially oil-rich Timor Sea have long been the subject of territorial disputes between Indonesia and each of Portugal, Australia and East Timor nationalists. In the marine area, there is the so-called Timor Gap, 61.000 sq km, between the Timor and Arafura Seas (between Australia's northern coast and the eastern part of Timor island). This is the subject of a treaty agreed in December 1989 by Australia and Indonesia. The area was also the subject of a case at the International Court of Justice in The Hague won by Australia against Portugal on June 30, 1995. Portugal had challenged Australia's right jointly to manage with Indonesia oil and gas exploration in the area. Indonesia had invaded East Timor, a former Portuguese colony, in late 1975 and annexed the territory in 1976. The Timor Sea as a whole, about the size of the North Sea, remains under- explored, with only about 104 exploration wells drilled there so far compared with more than 4,000 wells in the North Sea. The 1989 treaty and subsequent agreements have led to the creation of a joint Australian-Indonesian "Zone of Co-operation" (ZOC). Under the deal, the Timor Gap was divided into three zones for hydrocarbon exploration and for future resource exploitation: (1) the area nearest to Australia, Zone B, was to be exploited by Australia; (2) the area nearest to the eastern half of Timor island, Zone C, was to be exploited by Indonesia; (3) the area in between the two, Zone A (ZOCA), was to be exploited jointly through an authority, ZOCA, based in Darwin. E&P rights in the three zones cover depths ranging from 200 to 3,000 metres. All three zones are believed to be rich in hydrocarbons. Formations in the Timor gap include the Flamingo and Tithonian sands. Oil-bearing structures found there so far include: Jabiru, discovered in 1985 by BHP Petroleum of Australia and now producing of 15,000 b/d; Challis, producing 3,000 b/d; Elang, Baguio, Kakatua, Kaladin, Bebek and Jalak. Baguio straddles the two blocks. Gulf Canada has stakes in Jabiru and Challis. In the Indonesian Zone C, the Bonaparte Basin lies in deep waters and has interested a number of companies. Pertamina in late 1996 signed PSAs for two of this basin's blocks with two Japanese companies in Tokyo. The PSA for Sabo Block, 4,571 sq km, was signed with Japex. The PSA for Rabe Block, 6,400 sq km, was signed with Inpex. The deals involved signature bonuses of about $10m. Competitive bidders for these tracts included Mobil, BHP, Arco and Total. Inpex acquired more acreage there in 1998. Within the shared ZOCA, BHP Petroleum has a permit covering ZOCA 91-12, where it has the Bayu gas/condensate field. Phillips Petroleum of Oklahoma has the adjacent ZOCA 91-13, where the gas/condensate field Undan is connected with Bayu. About 60% of the Bayu/Undan structure is in BHP's block. In late March 1997 the two companies and ZOCA agreed for BHP to act as operator for Bayu/Undan. BHP wants an LNG plant to be built offshore in the field. Phillips, which built the first North American LNG plant in Kenai, Alaska, in 1969 to supply Japan and has its own "optimised cascade" technology, wants the LNG unit to be built onshore at Darwin which is 470 km to the south. These fields are rich in condensates. Bayu/Undan has 3.6 TCF of gas, with the LPG component estimated at 170m barrels of oil equivalent, and 400m barrels of condensates. Phase-1 production is expected to begin in 2001 at 60,000 b/d of condensate and 60,000 b/d of LPG from a fixed platform, with the output to be piped to a floating storage. Phase-2 by 2002 will produce 3m t/y of LNG. The partners of BHP and Phillips in this are Oryx Energy of the US, Hardy Oil of the UK, Inpex of Japan, and Santos, Petroz and Emet of Australia. Mobil has tested a deep play in the central zone. Its partners in this are Statoil of Norway, Shell, Mitsubishi and Hardy Oil. BHP has found and operates most of the oil-bearing structures in the Timor Gap. A first Jalak well in BHP's programme in 1995 was to test Tithonian sands, and wells were drilled at the other structures. By early 1995, BHP had drilled three wildcats at Elang: Elang-1, which had flowed at the rate of 5,800 b/d from a depth of 3,000 metres; Elang-2, which had flowed at 6,080 b/d; and Elang-3, 16 km away, which had flowed at 8,100 b/d. BHP recorded more than 100m barrels of very light oil and conducted further Elang drilling in 1995-96. Elang and Kakatua fields were developed BHP (42.4%) and began oil production in early 1998 at the rate of 17,000 b/d. This was raised to more than 30,000 b/d by late 1998. Eventually, BHP will develop the other fields in the region and will link them to a central production system. BHP's 15,000 b/d Jabiru ceased operation in 1996, as its floating production vessel was sent to Singapore for a safety review. Production was resumed in 1997. In 1998, BHP sold its 50% holdings in Jabiru and Challis to Gulf Canada. In September 1994, the Woodside Petroleum (Shell-BHP) announced a big oil discovery at its Laminaria-1 well, in Australia's Northern Territory. This is only 19 km outside the north-western part of ZOCA and close to Indonesia's marine territory outside the Gap. It is about 69 km west of the Elang discoveries. It is said the field could contain 200-300m barrels of oil. Nearby is the Corallina structure which has an important oil reserve. Both fields are being developed by Woodside at the cost of about A$900m ($714m) and should be on stream in 1999. Their combined capacity would be about 140,000 b/d of light/sweet oil. This new stream would be the most important replacement for Australia's declining Bass Strait oilfields, found in the mid-1960s by an Esso-BHP partnership, and some of Woodside's fields. (Woodside's 120,000 b/d Cossack field encountered technical problems in the autumn of 1996 and its production dropped to 50,000 b/d for more than four months. It was restored after extensive maintenance work). The first Laminaria-1 drillstem test was conducted over an interval of 3,292- 3,302 metres in a ten-hour period and produced a low gas/oil ratio of 40 cubic feet of gas per barrel. A total oil column of 102 metres was intersected between 3,207 and 3,309 metres. The well flowed at 5,900 b/d of 59 deg. API oil, through a half-inch choke with a well-head pressure of 960 psi. The oil had a minor content of hydrogen sulphide. The test covered 23 metres of the column's top and the lowest five-metre zone. There was no water with the oil, which suggested that the well contacted a high point in the reservoir. Later Woodside focused on the higher parts of the column. (In North-West Australia, Woodside Petroleum operates major gas/condensate and oil fields, including the Wanaea oilfield and the giant Perseus gas field which was discovered in 1995 and now is under development. It also operates the 7.5m t/y North West Shelf LNG complex, which is to have a 7m t/y expansion based mainly on Perseus. The other partners of the Shell-BHP combine in the LNG venture are BP, Chevron, Mitsui and Mitsubishi - see its profile in survey of LNG trade in Gas Market Trends, Vol. 43). In early April 1997, Australia awarded nine E&P permits for blocks near Laminaria, to Shell, Nippon Oil which got the most attractive tract, Coastal, Hardy Oil and four Australian firms: Woodside, Indo-Pacific, Cultus and Cartier Oil. Nippon Oil was to spend about $50m over three years and $25m in the second three-year phase. A total of $240m will be spent in exploring the nine blocks within six years.