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.
ABSJRllCrA drillinJ contractor has installed am operated on several offshore rigs, a e:::atprehensive data ao:;IUisition am cx:mprt:er processinJ system for realtime lOOllitorinJ of drillinJ operations am post event analysis. '!he system, which includes "smart alarms" for early warnirg of problems such as kicks, stuck pipe am drillstrinJ washouts, has been ext:erded to c:cver recent rec:x:mnerx:lations of the UK Department of Energy for High Pressure/High
From spud to TD, the Joanne 30/7a-Pl 1 well was drilled to a measured depth of 23,035' in 23.65 days. This extraordinary performance was achieved despite a 1600' sidetrack in an upper hole section. Adding time for skidding over the well slot, logging the reservoir interval, running and cementing the production liner and suspending the well brought the total time on the well to 31.65 days. The horizontal displacement for this extended reach well is 18,560', including a 4287' horizontal section in the thin Palaeocene Andrew sand reservoir. PI 1 was the eleventh well drilled on the Judy template using the Santa Fe Galaxy jack up drilling rig in Phillips J-Block development The drilling program featured a diligent and continuous search for methods to improve performance. This resulted in the implementation of several innovations during the course of the project A continuous improvement trend was clear throughout the template drilling project culminating in the PI 1 well. Several world records were set while drilling this well, including the 24 hour footage and total footage in a single run. This paper will present the techniques used in the P11 well to show how the impressive result was achieved.
Phillips Petroleum identified surface wellhead and blowout preventer (BOP) nipple up and nipple down time as an area where significant improvements in safety and savings in rig time could be made on the Audrey field in the southern North Sea UK sector. With a view toward future use on central North Sea high-temperature, high-pressure exploration and development wells drilled from heavy jack-up rigs, a unitized wellhead system designed for use with a single 18-3/4" BOP stack and a mudline suspension system has been fabricated and used successfully on three development wells on the Audrey Phase II Project and on one exploration well in the southern North Sea.
Phillips Petroleum identified surface wellhead and blowout preventer (BOP) nipple up and nipple down time as an area where significant improvements in safety and savings in rig time could be made on the Audrey field in the southern North Sea UK sector. With a view toward future use on central North Sea high-temperature, high-pressure exploration and development wells drilled from heavy jack-up rigs, a unitized wellhead system designed for use with a single 18-3/4" BOP stack .and a mudline suspension system has been fabricated and used successfully on three development wells on the Audrey Phase II Project and on one exploration well in the southern North Sea. INTROPUCTIONSubsea wellhead systems have evolved to the point where there is a standard configuration in common usage. This configuration uses an 18-314" 10M or 15M wellhead housing run on the 20" casing string with mandrel hangers for the 13-3/8" and 9-5/8" casing strings. The 18-3/4" BOP has a large enough diameter to permit drilling 17-112" hole without underreaming and a sufficiently high pressure rating for drilling to TD, yet is still small enough to be References and illustrations at end of paper handled without difficulty, particularly since most floating rigs are equipped with good BOP handling equipment. Because running and retrieving the BOP stack is time-consuming, a test stump for the BOP is provided to allow the stack to be tested on the surface. Use of a single stack keeps rig time spent running and retrieving BOPs to a minimum. All operations on the subsea wellhead are performed quickly using downhole tools run from the surface because of the prohibitive cost of manned intervention and the high cost of rig time. Despite the complexity of the equipment used in drilling with a subsea wellhead, this system has proven to be reliable and fast.In theory, nippling up and nippling down surface wellheads and BOPs should be much easier than running subsea wellheads and BOPs, since much less equipment is required and the wellhead and BOP are readily accessible. In practice, this is not the case. A major obstacle is that most jack-up rigs are equipped with two BOPs, a 21-114" 2M or 20-3/4" 3M BOP and a 13-5/8" 10M or 13-518" 15M BOP. Changing BOPs at least once is necessary on most wells in order to have a sufficiently high pressure rating for drilling to TD along with sufficiently large internal diameter to pass the drilling assemblies for the upper hole sections. Consequently, the limited availability of large-diameter, high-pressure BOPs on jack-up rigs has hindered the development of jack-up wellhead systems analogous to those currently in use on the vast 235
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