Planning a Tertiary Oil-Recovery Project for Jay/LEC Fields Unit

Abstract

Summary A major tertiary oil-recovery project is planned for the Jay/Little Escambia Creek (LEC) fields to recover an additional 47 MMbbl of oil. Ultimate recovery from the deep carbonate reservoir is expected to reach 393 MMbbl, or 54% of the 728 MMbbl oil originally in place (OOIP). Introduction The Jay/LEC fields, discovered in 1970, produce oil from a carbonate reservoir in the Florida panhandle and south Alabama. The fields were unitized in 1974, and waterflood operations have been underway for 7 years. This sour-oil field has been recognized for some time as an ideal miscible displacement candidate because (1) the crude is miscible with nitrogen, methane, and CO, at reservoir conditions and (2) about 382 MMbbf of oil are expected to remain following waterflood operations. Continuous tertiary recovery studies began in late 1977, and the working interest owners approved the project in June 1980, after 8 man-years of technical evaluation. Reservoir questions receiving special attention included injectivity of water following gas injection in a water-alternating-gas (WAG) operation and remobilization of residual oil trapped in the reservoir following water injection. A field injectivity test showed reduction in water injectivity would occur, and laboratory tests showed essentially all waterflood residual oil in place will be recovered from reservoir rock contacted by miscible gas. Additional study showed that decreased water injectivity following gas injection would be offset by excess injection capacity and some injection string changeouts. Recovery and performance estimates and WAG ratios were based on results obtained with two- and-three-dimensional reservoir simulation of representative sections of the reservoir. A modified version of Exxon's General Purpose Simulator (GPSIM) was used. Detailed reservoir description gave confidence in simulation studies and was an important factor in the decision to forego a pilot test. Nitrogen was selected as the principal injection gas rather than methane because of economics and rather than CO2 because of availability and economics. It will be injected alternately with water at rates of 67 MMcf/D until about 20% hydrocarbon pore volumes (HCPV) have been injected. A period of about 15 years of gas and water injection will be followed by injection with water until depletion. Ultimate oil recovery should be increased some 47 MMbbl, or 6.5% of the 728 MMbbl of OOIP. Ultimate recovery now is expected to reach 393 MMbbl of oil. Nitrogen will be purchased from a supplier with subsequent compression to 7,600 psig and distribution by the unit to existing injection wells. Facilities include injection compression, a field-wide distribution system, and a nitrogen rejection unit. Electric motors will be used as prime movers. Total investment is estimated at about $80 million. Nitrogen injection is targeted to begin in Dec. 1981. Reservoir and Fluid Properties Oil accumulation at Jay/LEC is in the Smackover carbonate and Norphlet sand formations. Oil occurs mostly in the dolomitized portions of the Smackover carbonate. JPT P. 1535

Development of mature oil fields — A review

“…Another cost effective reservoir development practice was to improve the volumetric sweep efficiency through the realignment of the injection and production wells (Zambrano et al, 1992). Surveillance of the secondary and tertiary Schiltz et al, 1984;Rowe et al, 1982 Twofreds (Delaware) Unit ( Christian et al, 1981;Langston and Shirer, 1983;Lawrence et al, 2002Garber (1916 CO 2 5-spot pilot ( Schiltz et al, 1984 recovery through performance monitoring, data acquisition and vertical conformance monitoring was reported to be an effective management strategy for mature fields (Stiles and Magruder, 1995). Reservoir characterization attempts for developing mature fields are also applied commonly.…”

Performance of Jay/LEC Fields Unit Under Mature Waterflood and Early Tertiary Operations

“…Unit owners approved the project in July 1980 following 8 years' technical evaluation. 2 It is planned tl;> inject miscible gas and water for 15 years until 20% HCPV of gas has been injected, and then to inject only water for an additional 8 years. Ultimate oil recovery should be increased by some 47x10 6 bbl [7.5X10 6 m 3 ], or 6.5% OOIP.…”

“…As expected, water injectivity has decreased significantly but presents no serious operational 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.…”

Very High Temperature Laboratory CO2 Injection

“…A previous experiment of MMP determination using a conventional slimtube apparatus was conducted at a temperature of 285 (Christian, Shirer, Kimbel, & Blackwell, 1981). Differently, the present study carries out the laboratory tests at a reservoir temperature of 270 This paper focuses on presenting the results of CO 2 injection obtained from both slimtube tests and native coreflood tests.…”