Planning a Tertiary Oil-Recovery Project for Jay/LEC Fields Unit
- L.D. Christian (Exxon Co. U.S.A.) | J.A. Shirer (Exxon Co. U.S.A.) | E.L. Kimbel (Exxon Co. U.S.A.) | R.J. Blackwell (Exxon Co. U.S.A.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1981
- Document Type
- Journal Paper
- 1,535 - 1,544
- 1981. Society of Petroleum Engineers
- 5.3.4 Reduction of Residual Oil Saturation, 7.3.3 Project Management, 5.1 Reservoir Characterisation, 5.6.4 Drillstem/Well Testing, 1.6.9 Coring, Fishing, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 4.6 Natural Gas, 5.7.2 Recovery Factors, 5.5 Reservoir Simulation, 5.4.1 Waterflooding, 5.1.1 Exploration, Development, Structural Geology, 4.1.4 Gas Processing, 5.4 Enhanced Recovery, 4.1.2 Separation and Treating, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 6.5.2 Water use, produced water discharge and disposal, 5.3.2 Multiphase Flow, 5.2 Reservoir Fluid Dynamics, 5.2.1 Phase Behavior and PVT Measurements, 4.3.3 Aspaltenes, 5.4.2 Gas Injection Methods, 5.6.9 Production Forecasting, 4.2 Pipelines, Flowlines and Risers, 5.8.7 Carbonate Reservoir
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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).
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.
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