Performance of Jay/LEC Fields Unit Under Mature Waterflood and Early Tertiary Operations
- E.P. Langston (Exxon Co. U.S.A.) | J.A. Shirer (Exxon Co. U.S.A.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- February 1985
- Document Type
- Journal Paper
- 261 - 268
- 1985. Society of Petroleum Engineers
- 3.3.1 Production Logging, 5.1.1 Exploration, Development, Structural Geology, 2.4.3 Sand/Solids Control, 1.6.9 Coring, Fishing, 1.6 Drilling Operations, 6.5.2 Water use, produced water discharge and disposal, 5.4 Enhanced Recovery, 4.2 Pipelines, Flowlines and Risers, 5.6.4 Drillstem/Well Testing, 5.7 Reserves Evaluation, 5.4.1 Waterflooding, 4.1.4 Gas Processing, 4.1.5 Processing Equipment, 5.1 Reservoir Characterisation, 5.4.2 Gas Injection Methods, 4.1.9 Tanks and storage systems, 5.6.5 Tracers
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Secondary oil recovery for the Jay/Little Escambia Creek (LEC) Fields Unit will exceed initial estimates by 27 x 10(6) bbl [4.3 x 10(6) m3] because of innovative reservoir management based on a comprehensive surveillance program and detailed reservoir description data. Infill program and detailed reservoir description data. Infill drill wells have accounted for 76 x 10(6) bbl [12 x 10(6) m3] of oil production. The mature waterflood was phased into a tertiary recovery project in 1981, and early phased into a tertiary recovery project in 1981, and early performance is generally consistent with the planning performance is generally consistent with the planning study, which predicted that 47 x 106 bbl [7.5 x 106 m3] of tertiary oil will be recovered.
The Jay/LEC field waterflood was initiated in 1974. Waterflood performance has been extremely good, as indicated by the estimated primary plus secondary reserves of 346 x 10(6) bbl [55 x 10(6) m3] being surpassed in May 1983 with the field producing 40,000 B/D [6400 m3/d] of oil at the time. Ultimate recovery from primary and secondary is now expected to be 373 x 10(6) STB [59 x 10(6) stock-tank m3] or 51 % of the original oil in place (OOIP). The major contributing factor to this success was effective reservoir management, which originated from results of reservoir description and surveillance programs.
Following 8 years' technical evaluation, a fieldwide miscible gas displacement project began in Jan. 1981 using available field methane gas. High-pressure N2 injection began in Dec. 1981 when this cheaper gas and high-pressure compression facilities became available. By mid-1984, 2.9% hydrocarbon pore volume (HCPV) of the 20% HCPV design of miscible gas had been injected. Current injection operations use a total of 61 x 10(6) cu ft [1.7 x 10(6) m3] N2 and 172,000 B/D [27 000 m3/d] water in a water-alternating-gas (WAG) scheme. As expected, water injectivity has decreased significantly but presents no serious operational problem. A total of 29 spinner surveys have been conducted problem. A total of 29 spinner surveys have been conducted in 18 injection wells (1) to define the initial gas profiles and (2) to determine the effects of injection pressure and duration of the gas injection cycle on the profiles. Initial nitrogen breakthrough occurred in Dec. 1982 and 14 of the 67 currently producing wells have experienced nitrogen production. Oil production response from these wells has been identifiable but varies significantly between wells.
This paper discusses the performance of the highly successful waterflood and describes how, in the later life of the flood, it was phased into the tertiary oil recovery project. project. Reservoir and Fluid Properties
The Jay/LEC field is located in the Florida panhandle and south Alabama. The oil accumulation is in the Smackover carbonate and Norphlet sand formations. Oil occurs mostly in the dolomitized portions of the Smackover. The formation is found below 15,000 ft [4572 m] and has an average thickness of about 350 ft [107 m]. All wells drilled in the field, including the infill wells, were cored conventionally through the Smackover formation.
Original reservoir pressure was 7,850 psi [54 MPa] about 5,000 psi [35 MPa] above the saturation pressure of 2,830 psi [20 MPa]. No free hydrocarbon gas pressure of 2,830 psi [20 MPa]. No free hydrocarbon gas has been released from the reservoir oil, since minimum pressure was 4,800 psi [33 MPa]. Table 1 presents a pressure was 4,800 psi [33 MPa]. Table 1 presents a summary of rock, fluid, and reservoir properties.
Following unitization and flood start in March 1974 a comprehensive surveillance program was implemented. Surveillance data were combined with the abundance of reservoir description information to provide a highly successful reservoir management program for this complex carbonate waterflood. Surveillance data were obtained from several production logging tools to determine initial and subsequent vertical flood conformance. Additionally, radioactive tracers, reservoir pressure surveys, and routine well test data were used to define areal conformance. Several programs to improve recovery evolved from this effort. Surveillance techniques and resulting programs are treated in more detail in Refs. 1 and 3. The programs are treated in more detail in Refs. 1 and 3. The infill drilling program, which began in 1977, is particularly significant. To mid-1984, a total of 37 infill particularly significant. To mid-1984, a total of 37 infill wells were drilled, and the average well spacing was reduced from 160 acres [647 x 10(3) m] per well to 112 acres [453 x 10(3) m]. Table 2 presents the updated results of this program. Infill wells have accounted for 76 x 10(6) bbl [12 x 10(6) m3] of oil production and currently are producing 17,200 B/D [2700 m3/d] oil.
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