This paper will review the history and current operations of the Kuparuk River Unit (KRU) field, the second largest field on the North Slope and one of the largest fields in the US. The field is a legacy asset in the ConocoPhillips portfolio with more than 6 BBO OOIP. The field came on line in December 1981 and has produced 2.25 BBO to date through water flood, immiscible water-alternating gas (IWAG) and miscible water-alternating-gas (MWAG) injections. Currently the field produces 90,000 bopd, 460,000 bwpd and 210 MMscf/d gas, and injects 570,000 bwpd and 160 MMscf/d miscible injectant. Some of the recent challenges at KRU include: maintaining pressure support (water injection) through an aging infrastructure, development and use of fit-for-purpose simulation models to support field management decisions, estimation of facilities back-out from a complex multi-field system, and optimization of one of the largest MWAG EOR floods in the world. History and current status of the KRU field will be discussed.
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 Magnolia field, located in the deepwater region of the Gulf of Mexico, produces oil and gas from a TLP in 4673' of water. The reservoirs comprise several stacked sandstone intervals within the early to mid Pleistocene with some minor production from the Miocene and Pliocene sands. A total of 8 wells have been completed, with the majority of the production from the B25 sandstone. The formation particle size is fine-grained sand to coarse silt and has relatively low K*H compared to other deepwater reservoirs. The reservoirs are significantly overpressured, highly compartmentalized, highly compacting and have experienced significant pressure declines in excess of 8000 psi in some cases during production. The wells were completed with cased hole frac packs and each completion included a permanent downhole gauge, enabling interpretation of the K*H and skin throughout the producing history of the wells to date. The perforating guns, frac fluids and screens were extensively tested prior to completion. The perforation shot size and density was carefully chosen and tested to achieve the required production. Well test results matched inflow analysis predictions. The initial skin values generally met expectations and improved during production due to a combination of well clean-up and reduced reservoir permeability from compaction. Proppant integrity has been maintained under extreme depletion (>8000 psi) conditions. Productivity was measured using perforation tunnel permeability (Kpt) analysis. The Kpt values were analyzed over the course of production and compared to similar type completions. The Kpt benchmark analysis shows that the completions are among the best in class. Well productivity has met or above expectations, and the longevity has exceeded expectations in most cases. Introduction The Magnolia field is located in the deepwater region of the Gulf of Mexico in Garden Banks, Blocks GB783 and GB784 (Figure 1). The field was discovered in 1999 with the GB783–1 exploration well and brought on production in December 2004. The field was developed using a Tension Leg Platform (TLP), which sits in 4673' of water and produces both oil and gas from 8 wells. The field has hydrocarbon pay in at least fifteen sand sequences, ten of which have been targeted for development. Most of the reservoirs are Pleistocene, however two minor Pliocene reservoirs, and one minor Miocene reservoir are also present (Figure 2). More than 80% of the recoverable volumes are from the lowermost Pleistocene sands, the B20, B25 and B30, with some 60% of the predicted recovery expected from the B25 reservoir. Both oil and gas bearing sands are present at various levels in the field, with everything from highly undersaturated (4000-7000 psi), good quality (~38 API, GOR ~1800 scf/stb) crudes in much of the B20, B25 and B30 reservoirs, saturated crudes, rich gas-condensates (>100 stb/MMscf) to dry gases in some of the shallower intervals. The sands are deepwater turbidite deposits, including sheet sands, amalgamated and braided channel sands, levee and overbank facies. There is significant faulting due to deformation by an underlying salt diaper, resulting in significant compartmentalization of the field. The main B25 reservoir is further compartmentalized stratigraphically due to three main amalgamated channel bodies. A net pay map for the B25 is presented in Figure 3, with the main channel bodies and fault blocks highlighted. An East-West seismic line through the field further highlights Magnolia's structural and stratigraphic complexity (Figure 4). Initial reservoir pressures vary significantly by fault block as well as by reservoir unit, with the initial pressure in the B25 reservoir typically 9,500 to 11,000 psia. A pressure plot of the largest reservoir the B25 demonstrates the significant compartmentalization (Figure 5). The reservoir temperature is fairly low, typically 145 to 160 degrees F.
Summary The Magnolia field, located in the deepwater region of the Gulf of Mexico, produces oil and gas from a tension leg platform (TLP) in 4,673 ft of water. The reservoirs comprise several stacked sandstone intervals within the early to mid Pleistocene with some minor production from the Miocene and Pliocene sands. A total of eight wells have been completed, with the majority of the production from the B25 sandstone. The formation-particle size is fine-grained sand to coarse silt and has relatively low K*H compared to other deepwater reservoirs. The reservoirs are significantly overpressured, highly compartmentalized, highly compacted, and have experienced significant pressure declines in excess of 8,000 psi in some cases during production. The wells were completed with cased-hole frac packs and each completion included a permanent downhole gauge, enabling interpretation of the K*H and skin throughout the producing history of the wells to date. The perforating guns, frac fluids, and screens were extensively tested before completion. The perforation-shot size and density was carefully chosen and tested to achieve the required production. Well test results matched inflow analysis predictions. The initial skin values generally met expectations and improved during production because of a combination of well cleanup and reduced reservoir permeability from compaction. Proppant integrity has been maintained under extreme depletion (>8,000 psi) conditions. Productivity was measured using perforation tunnel permeability (Kpt) analysis. The Kpt values were analyzed over the course of production and compared to similar type completions. The Kpt benchmark analysis shows that the completions are among the best in class. Well productivity has met or is above expectations, and the longevity has exceeded expectations in most cases.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.