Guntis Moritis
Drilling/Production Editor
Indonesia is moving forward strongly on several fronts, including enhanced oil recovery, in hopes of staying ahead of rising domestic consumption.
The Duri steamflood operated by P.T. Caltex Pacific Indonesia (CPI), a Texaco Inc. and Chevron Corp. joint venture, under a production sharing contract with Pertamina, the Indonesia state oil company, has significantly added to Indonesia's proved reserves and production capability.
The dedication by the government and the operator of the steamflood took place last March after the project had exceeded the production rate at the Kern River, Calif., field, heretofore the largest of this type in the world.
The proved reserves from this $1.8 billion Duri project are calculated to be 2 billion bbl of heavy (22.7 API) oil from the Pertama and Kedua sands (first and second sands). Production is expected to reach 330,000 bo/d by 1993 (Fig. 1). Currently this central Sumatran field is producing 160,000 bo/d, a considerable increase over the 40,000 bo/d prior to the start of the steamflood in 1985.
Potentially another 1 billion bbl of recoverable tertiary oil lies in other sands of the field.
Duri contains a significant portion of the remaining oil reserves in Indonesia. Although Indonesia does not publish recoverable reserve numbers, recently the Minister of the Department of Mines, Ginandjar Kartasasmita, said that the proved and probable reserves in Indonesia are 11 billion bbl of oil and 97 tcf natural gas. Estimates of the portion of the oil reserves that fall into the proved (developed plus undeveloped) category range from 4.9 to 8.3 billion bbl.
Production from Duri will also help delay the time when domestic consumption overtakes total production in Indonesia. Currently, this crossover is estimated to occur sometime between 1997 and 2005.
To delay this, Indonesia has also over the past few years increased the incentives for exploration and additional development work in producing areas.
DURI PRODUCTION PLAN
To implement the steamflood, the 15,100-acre Duri field has been divided into 12 separate development areas. Fig. 2 shows the schedule for the first eight areas.
To date, $700 million of a planned $1.8 billion has been invested in the steamflood. Cumulative tertiary oil produced is 100 million bbl. Cumulative total production is 525 million bbl of the estimated 7.1 billion bbl of oil in place. Original oil in place of the two sands, Pertama and Kedua, included in the steamflood is 4.1 billion bbl.
Unless additional gas supplies are found, about 20% of the oil will be burned to generate the steam. The oil is low in sulfur and therefore burning will not create an environmental problem.
Currently only enough gas, 52 MMscfd, is available to generate electricity for such needs as electric motors on the sucker rod pumping units and the large camp facilities.
The camps house about 26,000 CPI employees, contractors, and their families in this relatively remote region on the island of Sumatra. There is no excess gas available for raising EOR steam.
In Duri, CPI employs 6,200 people, of which 109 are expatriates.
DEVELOPMENT TO DATE
The Duri field was discovered in 1941 and placed on production in 1958. Peak production of 65,000 bo/d occurred in 1964 before declining to a plateau of about 40,000 bo/d from 1967 to 1984. Attempts at tertiary recovery starting in the 1960's proved unattractive. Both cyclic steam injection and caustic pilots were attempted.
A steamflood pilot was started in 1975, and design for the area wide flood began in 1981 (OGJ June 8, 1981, p. 21 8).
Steam injection started in the first area in April 1985. The flood pattern in the first four areas is a 3 7/8-acre, seven spot consisting of 1 dual completed steam injection well and 12 producing wells, 6 completed in the Pertama and 6 in the Kedua sand (Fig. 3).
Except for Area 2, the initial pilot, each area is about 1,500 acres. A schematic of flow is shown in Fig. 4.
The general plan is to inject steam in each area for 6 112 years followed by water for another 2 1/2 years. The water injection will increase the vertical sweep efficiency in the 1 00-ft thick sands.
Steam injection into Area 4 was to begin in April, and work on Area 5 has started.
Dedication of the steamflood took place on Mar. 3 after the field surpassed the daily production rate of the Kern River steamflood, previously the world's largest.
Currently, there are 1,348 producing wells pumping 160,000 bo/d (128,000 bo/d net) and 500,000 bw/d. All of the water is injected as steam into the 336 injection wells. A total of 230, 50 MMBTU steam generators are in operation.
FUTURE WORK
New reservoir simulation results and the performance of the first three steam injection areas have determined that a hybrid nine and five-spot pattern is more optimal. Starting with Area 6, the injection pattern will be changed to a nine spot in the thicker portions of the reservoir, and a five spot along the edges.
Also, twin wells will no longer be used to produce the Pertama and Kedua sands separately. Both zones will be produced from the same well bore.
By eliminating the additional well, the total number of producers that will ultimately be needed has decreased to 3,202 from the previously planned 4,060. Eventually a total of 1,408 injection wells will be needed. Peak production is estimated to be 330,000 bo/d (270,000 bo/d net) and 1,250,000 bw/d. The steam injection rate will be at 995,000 bw/d.
The peak number of generators is expected to reach 300. As older areas revert to water injection, steam from these generators will be piped to new areas. The steam generators from Area 1 will become available in 1993 for injecting steam into Area 6.
ADDED RECOVERY POTENTIAL
Besides the Duri steamflood, Sumatra is becoming a very active waterflood area. Caltex has seven waterfloods planned (Table 1). These are expected to recover 800 million bbl of secondary oil.
The largest project, Minas, has a primary recovery of over 3 billion bbl and is currently producing at 230,000 bo/d under a peripheral waterflood started in 1970. By changing to a pattern waterflood, an additional 500 million bbl of oil are expected to be recovered.
The Minas field also has tertiary recovery potential. Steam is a possibility even though the reservoir at 3,000 ft and the oil of 32 API gravity are almost beyond the criteria usually considered for steamflooding.
To accelerate development of secondary recoverable oil reserves, Pertamina has signed five EOR (enhanced oil recovery) contracts. Mainline Resources (O.S.) Ltd. has a contract on Bunyu Island.
Triton Indonesia Inc. acquired the Muara Enim block in South Sumatra. Husky Oil International Inc. is on the Limau block in South Sumatra. Southern Cross has the Tanjung block, and Asamera Ltd. is in the Jambi block in Sumatra.
As an incentive for companies to make additional investments in producing areas, Pertamina, in 1989, began signing extensions on contracts set to expire in the next 10 years.
Five extensions were signed in 1989. These were with Asamera, Mobil Oil Indonesia Inc., Tesoro Indonesia Petroleum Co., and Stanvac Indonesia P.T. Negotiations with CPI, Conoco Indonesia Inc., and Huffco Indonesia are now taking place.
EXPLORATION POTENTIAL
Recent modifications to production sharing contracts are helping Indonesia sign more contracts. A total of 19 contracts were signed in 1989, up from only 10 in 1988. Pertamina is aiming to sign 20 contracts in 1990.
The areas with the greatest potential are in the eastern part of Indonesia that is relatively unexplored. This area includes possible extension into Irian Jaya of the discoveries made by Chevron Niugini Pty. Ltd. in Papua New Guinea.
Also deepwater (greater than 400 ft) is another potential that is sparsely explored in eastern part of Indonesia.
Cost to explore for and develop the eastern areas will be high. The general outlook is that no one expects to encounter billion barrel fields there, but 100 million plus fields are possible. Some believe that this area is the most likely to yield the largest finds in the next decade for Indonesia.
The Timor Gas Agreement signed in December 1989 between Indonesia and Australia will open up another area for exploration. New blocks in East Timor are expected to be offered later in 1990.
NEW FIELDS ON STREAM
In 1989, four new fields went on stream with a total initial production of 65,000 bo/d. These included the MSN field operated by Hudbay Oil (Malacca Strait) Ltd., Intan field operated by Maxus Southeast Sumatra Inc., Ikan Pari field operated by Conoco Indonesia Inc., and KF field operated by Marathon Petroleum Indonesia Ltd.
Three significant fields are slated to start production in 1990. Amoseas Indonesia Inc.'s Anoa field is expected to produce 25,000 bo/d beginning in June. The Camar field operated by Enterprise Oil Exploration Ltd. should start producing another 25,000 bo/d also in June. The largest field found in recent years, Maxus's Widuri (estimated recoverable reserves of 225 million bbl) is expected to start in December at rates above 100,000 bo/d.
Faisal Abda'oe, president director of pertamina, has recently said that Pertamina prefers that fields like Widuri be produced at rates with longer production plateaus instead of a sharp maximum peak rate followed by a sharp decline.
GAS
In 1989, Indonesia gas production averaged 5.7 bcfd. Deliveries to Taiwan from the Bontang LNG plant will start in June.
Pertamina recently signed two new gas supply contracts. One is with Chubu Electric (Japan) to supply an additional 0.5 million metric tons of LNG starting in 1990. The other, starting in March 1992, is with PLN (Indonesian Electric Authority) to supply 180 MMcfd for a power plant near Surabaya on the island of Java.
The gas to PLN will come from Atlantic Richfield Indonesia Inc.'s Pagerungan field in the Kangean block.
Planning for installing a gas pipeline grid for the entire island of Java is under way.
Discussions are taking place to add a sixth LNG train in Bontang in 1994.
A seventh may be installed in 1996, and also a seventh could be added to the Arun LNG plant in 1995.
Plans have been announced for a three-train LNG installation on Natuna island. Both Esso Indonesia Inc. and Conoco have large gas discoveries. Esso's field is estimated to contain 45 tcf with a very high CO2 content. Feasibility studies on piping this gas to Batam Island, near Singapore, are also taking place.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
