Georges Raimondeau Suharmoko
Total Indonesie
Balikpapan, Indonesia
The development of Tambora and Tunu gas fields in Kalimantan has increased available gas supply for the export of liquefied natural gas (LNG) from Indonesia.
The demand for LNG is increasing in the energy thirsty Far East market. And Indonesia, the world's largest exporter, is keeping pace by expanding the Bontang liquefaction plant in East Kalimantan.
A fifth train, with a capacity of around 2.5 million tons/year, began operating in January 1990. Start-up of a sixth train, of identical capacity, is planned for January 1994. The Bontang plant is operated by PT Badak on behalf of Pertamina, the Indonesian state oil and gas mining company.
The feed to the fifth train comes primarily from the first-phase development of Total Indonesie's two gas fields, Tambora and Tunu. The sixth train will be fed by a second-phase development of the Tunu field.
Through an early production scheme, gas production from the Tambora and Tunu fields started on Dec. 27, 1989, and Aug. 10, 1990, respectively. Initial capacity was 240 MMcfd, The export capacity was increased to 300 MMcfd on Dec. 7, 1990, with the start-up of the central processing unit (CPU) and boosted to 380 MMcfd on Jan. 5, 1991, after the CPU was debottlenecked.
THE MAHAKAM PERMIT
Tambora and Tunu fields are located in the Mahakam permit operated by Total Indonesie in East Kalimantan province. Total Indonesie and Indonesia Petroleum Ltd. (inpex) each has a 50% interest in the production-sharing contract (PSC) with Pertamina.
The Mahakam PSC covers an area of 8,000 sq km (2 million acres) offshore East Kalimantan.
The length exceeds 200 km (124 miles) in a northnortheast/south-southwest axis (Fig. 1).
The PSC includes the entire Mahakam River delta located at 0.401 south, 117.25 east, just below the equator. The delta is covered with mostly uninhabited mangrove forest and nipah palm trees. Some areas are flooded at high tides. The climate is hot (30 C.) and humid (92% relative humidity) throughout the year.
Total Indonesia started oil production in 1974 from the Bekapai offshore field, and in 1975 from the giant Handil field located in the delta. The oil production from both fields is exported from Total's Senipah terminal.
Since 1982, the associated gas from the Bekapai and Handil fields is compressed and sent for export to the Bontang liquefaction plant at a rate of 180 MMcfd. The first phase development of Tambora and Tunu has more than tripled the Mahakam gas export capacity.
The Mahakam PSC has recently been extended for 20 years from 1997 to 2017. This extension has reinforced Total Indonesie's determination to find additional gas reserves for fueling Indonesia's gas export capability.
TAMBORA FIELD
The Tambora field is located in the Badak-Nilam-Handil trend of the Mahakam area. This structure covers approximately 70 sq km (17,300 acres). Between 1974 and 1987, at least 35 wells were drilled since the field's discovery.
The main structural trends are:
- In the north, the continuity of the narrow Nilam anticline with a large perisyncline closure.
- In the South, a monoclinal trend dipping eastwards.
In this deltaic environment, geological correlations are often tricky due to sharp facies variations, mainly in deltaic plains deposits. However, 125 oil and gas bearing reservoirs were identified between 2,500 to 4,300 m (8,202-14,107 ft) below sea level.
The hydrocarbon-bearing sands are divided into four zones, named from top to bottom, D, E, F, and G. The reservoirs are mostly straight east-west sandy channels, 215 m (6-50 ft) thick and 1-2 km (0.6-1.2 miles) wide with sharp north-south boundaries.
Some bar-type reservoirs are encountered with important lateral extensions and reduced thicknesses.
More than half of the proven oil (60%) is located in the D zone.
Oil volume decreases sharply below this level, and no oil has been encountered in the G zone.
The vertical proven gas distribution is more regular with a progressive increase from D to G zones. The G zone contains a third of the gas-in-place with reservoirs generally thicker and filled up to spill point.
A small amount of oil production from oil rings located north of the structure was started in 1985, with peak production reaching 10,000 b/d. Oil strings are now produced commingled with the gas zones.
TUNU FIELD
Tunu field is located in the outer margin of the present Mahakam delta. The structure lies in the Attaka-Bekapai trend approximately midway between these two fields. The structure, over 65 km (40 miles) long, is a very gentle asymmetrical anticline elongated north-south.
The areal closure of the structure is more than 400 sq km (98,800 acres). Between 1971 and 1987, the field was intensively explored and delineated by 31 wells of which only 3 were unsuccessful.
The discovery was made in 1973 with well TN-10 (previously TB-1), but this well did not penetrate the whole producing interval.
The TN-2 well, drilled in 1982, represented the true discovery. The well penetrated the entire pay horizon. With the decision to develop the field, two additional delineation wells were drilled in 1990-91 with positive results.
The sand percentage decreases from west to east.
Sand bodies in the pay zone are mainly of bar type, 2-3 m thick. A few 10-15 m thick channels were also found. The facies vary from upper tidal delta plain to marine delta front.
The producible pay zone (pressure equivalent density less than 1.15) of Tunu field is located below 2,200 m (7,218 ft) and down to 4,000 m (13,123 ft). The maximum accumulation of proven gas net pay is found between 2,500 and 3,650 m on the crest of the structure.
Except for a single oil-bearing reservoir encountered at TN-5, all other reservoirs contain wet gas. The average condensate yield is 40 bbl/MMcf of gas. The API gravity is between 40 and 50.
The proved gas net pay ranges from 10 to 90 m, with an average of 40 m/well. Typically for this net pay and sand characteristics, the average initial gas potential is 40 MMcfd with a wellhead pressure above 1,300 psi.
Because the sand bodies are of variable petrophysical qualities, multilayered, thin, and very difficult to correlate, the development philosophy is based on a systematic approach. A regular 1,500 m square pattern was chosen for the first two phases of development.
RESERVES
With potential reserves in excess of 5 tcf, Tambora and Tunu fields will make significant contribution to the East Kalimantan gas system supplying the Bontang liquefaction plant and the Kaltim fertilizer plant.
Reserves estimates will be firmed up as production history is progressively taken into account and additional delineation and development wells are drilled.
GAS CHARACTERISTICS
The natural gas contains 57% CO2. Traces of H2S have also been detected on some of the Tunu wells. This high CO2 content coupled with high pressures (up to 4,500 psi wellhead shut-in pressure) and high temperatures (up to 100 C.) has justified the use of stainless steel for completing the wells.
Each well is equipped with a single string of 41/2-in. stainless steel tubing and a monobloc stainless steel christmas tree, series 5,000 psi.
FIRST PHASE
Fig. 2 illustrates the first phase development for the two fields. The main considerations were:
- Develop the northern part Of Tambora field (most productive zone) with an initial production capacity of 150 MMcfd from two gathering and testing satellites (GTS).
- Develop the central part of the Tunu field (thicker cumulative pay zone) with an initial production capacity of 100 MMcfd from one GTS.
- Centralize the gas process, control, and treatment units at one CPU of the Tambora field along one branch of the Mahakam river.
- Interconnect the 20-in. export gas line feeding the Bontang liquefaction plant.
- Export the condensate being produced to the Handil stabilization facilities through a 10-in. line.
Fig. 3 is a schematic of the pipeline system. The early development of the central Tunu structure will confirm the main reservoir hypotheses to allow assessment of this most promising field.
The gas/condensate mix is produced from unmanned, single-well platforms connected by individual 6-in. flow lines to GTSs. The GTSs are also hot normally manned. Each GTS can accommodate:
- Up to 10 producing wells
- Necessary manifolding
- Choke valves (some remotely controlled to adjust the gas flow)
- One stainless steel clad test separator
- A control panel and a remote terminal unit powered by a thermoelectric generator run on gas
- A Pig launcher for the 12-in. trunk line connecting the GTS to the CPU.
The CPU supports all processing, control, and treatment facilities for both Tambora and Tunu fields.
The Tambora gas, condensate, and oil production is routed into two high-pressure, three-phase separators in parallel. The operating pressure is 75 bar (1,087 psi).
The Tunu gas and condensate production is routed at first into a high-pressure slug catcher, then mixed with Tambora production. The gas is then dried in a glycol contactor to export specifications (less than 20 lb of water/MMcf), metered, and exported.
Before being pumped to Handil, the mix of condensate and oil is routed to two separators in series. The first stage (MP) is at 25 bar (362 psi), and the second stage (LP) is at 7 bar (101 psi).
The gas from the MP and LP separators is compressed and reinjected into the main gas stream. The oily water is treated down to a maximum hydrocarbon content of 25 ppm before being discharged to the river.
Various offsite facilities are associated with the CPU. These include:
- One 45 m high flare
- One 75 m high telecommunication tower
- One fire station platform with two 650 cu m/hr (4,089 bbl/hr) diesel fire pumps.
Because the CPU serves as central control for both Tambora and Tunu fields, support facilities include accommodation for 90 people, offices, well base, work shop, infirmary, marine facilities, and helipad.
The first development phase took advantage of the existing vertical exploration or delineation wells which were worked over and completed. No new wells are being drilled.
Nine wells were initially connected to Tambora GTS-1, four wells to GTS-2, and four wells to Tunu GTS-A. Additional wells will be worked over or drilled when needed to maintain the GTS's production capacity.
CONSTRUCTION
Because both Tambora and Tunu fields are either in a mangrove-type environment or shallow water (less than 2 m depth), the CPU and the GTSs were designed with a single-piece deck. This design maximized onshore construction. Minimal hookup and commissioning activities were required on site.
The CPU deck is 80 m long x 30 m wide and weighs 2,600 tons (830 tons for the structure alone). The deck is supported by sixteen piles, 42 in. diameter x 1.5 in. wall, with a penetration of approximately 40 m. The deck was skidded onto a large cargo barge, towed to site, and placed in between the predriven piles. The CPU installation procedure is shown in Fig. 4.
For each GTS the deck measures 20 m x 22 m and weighs 230 tons (100 tons structural and 130 tons of equipment). The deck is supported by four 36 in. x 1 in. piles. The installation followed the same principle as the CPU deck.
The overall project cost came to $97 million ($132 million including the well workovers).
SECOND PHASE
A second phase of development for the Tunu field has been launched and should be finished in January 1994. This second phase will increase the total gas export capacity from the Tambora and Tunu fields to about 1 bcfd with 40,000 b/d of condensate.
To meet LNG export demands, an early production scheme will start in January 1993. This scheme will increase production capacity to 600 MMcfd.
This second phase will develop the southern part of Tunu field with an additional 4-5 GTSs (36 additional wells).
The gas and condensate production will be routed through a new 32-in. trunk line to a new central processing unit adjacent to the existing CPU. The gas will then be sent to the Bontang liquefaction plant through a new 32-in. line to Badak, and a new 36-in. line from Badak to Bontang.
With this second phase, Total Indonesie will maintain its position as a major gas producer in Indonesia. Also, recent gas discoveries at Sisi and North West Peciko, and additional delineation of the Tunu field should bring enough additional reserves to sustain that position well into the next century.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.
