Bayu-Undan Field: Appraisal and Development Planning
Abstract: The Bayu-Undan Field - located offshore in the Timor Gap Zone of cooperation Area A (ZOCA) between Australia and Indonesia is a significant "world class" gas-condensate resource. A group led by Phillips Petroleum Company discovered the field in 1995 with the drilling of the Bayu #1. A group led by BHP Petroleum confirmed this discovery as a large accumulation with the drilling of the Undan #1. These two wells are 6 miles apart. This paper will present the results of the appraisal and conceptual development pla… Show more
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The Bayu-Undan gas recycling project is located north of Australia, in the East Timor Sea and is designed to produce 1,100 MMscf/D of wet gas, strip out 110,000 B/D of condensate/LPG, initially reinject 950 MMscf/D of lean gas, and later export up to 700 MMscf/D of lean gas to a LNG plant in Darwin. The initial development called for 16 North Sea-style, 7 in. monobore wells (11 producers and 5 gas injectors). By May of 2003, it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instability. Without the production contribution from these wells, the first year's production target would not be met. To meet the production targets, a complete well redesign was undertaken. First, the tubing was upsized from 7 in. to 9–5/8 in. Then semi-openhole completions with pre-drilled liners and openhole packers were selected instead of the conventional cased and perforated design to reduce installation time. Finally, oil based drill-in fluid was selected to provide lubricity, temperature stability, and low liftoff pressure of the filter cake for rapid cleanup. Utilizing the Big Bore design, the production capacity of +1.1 Bcf/D and injection capacity of 1.1 Bcf/D was achieved in June of 2004, ahead of schedule. The well count was also reduced from 16 to 12 wells (8 producers and 4 gas injectors.) Two producers had capacities in excess of 300 MMscf/D, and three gas injectors had injection capacities in excess of 350 MMscf/D. The increased production resulted in 19 MMstb of condensate/LPGs produced in the first year, some 7–8 MMstb more than would otherwise have been the case. Introduction The Bayu-Undan Field is a retrograde gas-condensate field with a raw Gas-Initially-In-Place (GIIP) of 8–9 Tcf including 700 MMstb propane plus (C3+). The field is located in the Timor Sea and straddles the Joint Petroleum Development Area, JPDA. The Production Sharing Contracts, PSCs, 03–12 and 03–13 in the Timor Gap area are administered jointly by the countries of East Timor and Australia as seen in Figure 1. The Bayu-Undan gas recycling project was originally planned to be developed from two platforms, with eight - 7 in. monobore wells and eight - 7–5/8 in. monobore wells, consisting of 11 producers and five gas injectors. The planned well depths ranged from 4000 m (11,972 ft) to 6341 m (20,798 ft). This design would require well rates up to 220 MMscf/D, to meet the design premise of producing 1100 MMscf/D while re-injecting 950 MMscf/D of lean gas by July 2004. By 2006, when the LNG plant and pipeline were available, 475 MMscf/D would be transported to the LNG plant in Darwin and the remaining 475 MMscf/D of lean gas reinjected into the formation.1 The Bayu-Undan formation structure is a broad east-west trending horst with a number of culminations set up by internal eastwest and north-south trending faults as seen in Figure 2. The predominant hydrocarbon-bearing section of the Bayu-Undan Field occurs in the upper part of the Early to Middle Jurassic Plover Formation and throughout the Later Jurassic Elang Formation. In addition, a thin interval belonging to the Frigate and the Flamingo Formations forms a minor part of the pay zone, along the margins of the field. One distinct feature is a common gas-water-contact (GWC) interpreted across the field at 3109 mSS TVD (10,198 ft). Figure 3 presents a generalized stratigraphic column and reservoir characterization for Bayu-Undan.
The Bayu-Undan gas recycling project is located north of Australia, in the East Timor Sea and is designed to produce 1,100 MMscf/D of wet gas, strip out 110,000 B/D of condensate/LPG, initially reinject 950 MMscf/D of lean gas, and later export up to 700 MMscf/D of lean gas to a LNG plant in Darwin. The initial development called for 16 North Sea-style, 7 in. monobore wells (11 producers and 5 gas injectors). By May of 2003, it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instability. Without the production contribution from these wells, the first year's production target would not be met. To meet the production targets, a complete well redesign was undertaken. First, the tubing was upsized from 7 in. to 9–5/8 in. Then semi-openhole completions with pre-drilled liners and openhole packers were selected instead of the conventional cased and perforated design to reduce installation time. Finally, oil based drill-in fluid was selected to provide lubricity, temperature stability, and low liftoff pressure of the filter cake for rapid cleanup. Utilizing the Big Bore design, the production capacity of +1.1 Bcf/D and injection capacity of 1.1 Bcf/D was achieved in June of 2004, ahead of schedule. The well count was also reduced from 16 to 12 wells (8 producers and 4 gas injectors.) Two producers had capacities in excess of 300 MMscf/D, and three gas injectors had injection capacities in excess of 350 MMscf/D. The increased production resulted in 19 MMstb of condensate/LPGs produced in the first year, some 7–8 MMstb more than would otherwise have been the case. Introduction The Bayu-Undan Field is a retrograde gas-condensate field with a raw Gas-Initially-In-Place (GIIP) of 8–9 Tcf including 700 MMstb propane plus (C3+). The field is located in the Timor Sea and straddles the Joint Petroleum Development Area, JPDA. The Production Sharing Contracts, PSCs, 03–12 and 03–13 in the Timor Gap area are administered jointly by the countries of East Timor and Australia as seen in Figure 1. The Bayu-Undan gas recycling project was originally planned to be developed from two platforms, with eight - 7 in. monobore wells and eight - 7–5/8 in. monobore wells, consisting of 11 producers and five gas injectors. The planned well depths ranged from 4000 m (11,972 ft) to 6341 m (20,798 ft). This design would require well rates up to 220 MMscf/D, to meet the design premise of producing 1100 MMscf/D while re-injecting 950 MMscf/D of lean gas by July 2004. By 2006, when the LNG plant and pipeline were available, 475 MMscf/D would be transported to the LNG plant in Darwin and the remaining 475 MMscf/D of lean gas reinjected into the formation.1 The Bayu-Undan formation structure is a broad east-west trending horst with a number of culminations set up by internal eastwest and north-south trending faults as seen in Figure 2. The predominant hydrocarbon-bearing section of the Bayu-Undan Field occurs in the upper part of the Early to Middle Jurassic Plover Formation and throughout the Later Jurassic Elang Formation. In addition, a thin interval belonging to the Frigate and the Flamingo Formations forms a minor part of the pay zone, along the margins of the field. One distinct feature is a common gas-water-contact (GWC) interpreted across the field at 3109 mSS TVD (10,198 ft). Figure 3 presents a generalized stratigraphic column and reservoir characterization for Bayu-Undan.
A case study is presented showing how reservoir characterization with geostatistical modeling was used to develop the reservoir flow simulation model for Bayu-Undan Field. The modeling was tailored to both reservoir type and the selected development scenario. Bayu-Undan Field is currently under development as a gas recycle project with future gas export. The reservoir is made up of both fluvial and marine sedimentary sequences. The need to predict fluid flow for both recycle and depletion scenarios in the presence of these reservoir types requires an understanding of reservoir heterogeneity and a method to preserve it in an upscaled flow simulation model. The major control on reservoir character is facies type which controls grain size, sedimentary structure and degree of bioturbation. Facies were determined from log motif and core description. Different statistical techniques were chosen to build facies models for the continuous marine zones and the heterolithic marine/fluvial zones. Numerous facies realizations were constructed to evaluate the possible range of outcomes and uncertainties. Porosity was distributed either deterministically using a weighted average algorithm or statistically using variograms. Permeability was distributed using a porosity-based transform. A number of permeability upscaling algorithms were evaluated to ensure reservoir heterogeneity was preserved when upscaling from the geocellular model to the flow simulation model. As a result, separate algorithms were chosen for horizontal permeability in marine and fluvial units, and for vertical permeability. Use of these upscaling techniques resulted in very good preservation of gas in place by permeability class, shown by comparing the geocellular model with the upscaled model. The modeling captured and preserved the reservoir flow characteristics critical to performance predictions for the gas recycle project. Introduction The Bayu-Undan Field is located in the Zone of Cooperation A (ZOCA) in the Timor Sea 280 miles northwest of Darwin, Australia. It is approximately mid-way between Australia and the island of Timor, Figure 1. The field was discovered in 1995 and is a retrograde gas-condensate reservoir1. Reserves are 400 MM bbls of associated liquid hydrocarbons with potential gas sales of 3.4 tcf. The reservoir rock is low porosity sandstone, 8–15%, with relatively high permeability, up to 2000 md. In addition to the discovery well, 10 appraisal wells have been drilled. Extensive open hole logging has taken place and approximately 3500 ft of reservoir section has been cored. A total of 15 drill stem tests (DST) were taken on the discovery and appraisal wells. Information from the log analyses, detailed core descriptions, DST analyses and further petrologic studies form a huge database describing the reservoir. A gas recycle liquids recovery project is currently under development but the option for future gas export remains open. Due to its offshore location, field development costs will be high. To control and reduce development risks and uncertainties, reservoir performance modeling needed to be of the highest practical accuracy. The extensive database and access to state of the art modeling software provided the tools for this reservoir characterization project.
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