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

A one-well field test of nitrogen WAG (water alternating gas) injectivity was conducted to detennine whether a reduction in water injectivity would occur after injection of nitrogen. A 40% reduction was observed immediately after nitrogen injection. Following three short WAG cycles, water injectivity increased to its pretest level with injection of a large volume of water. FEBRUARY 1982 Perforated interval, m (tt) Initial reservoir temperature, °C (OF) Cooled reservoir temperature, °C (OF) Reservoir pressure, Pa (pSi) Net thickness, m (tt) Average porosity, % Average core permeability, m 2 (md) Water injected before start

An enriched, Water-Alternating-Gas (WAG), miscible flood was brought on stream in December 1982 in the Prudhoe Bay Field on Alaska's North Slope. This Prudhoe Bay Field on Alaska's North Slope. This paper outlines details of the Project and traces paper outlines details of the Project and traces its evolution from conceptual engineering through start-up to initial performance. The Project involves an area containing 442 million barrels original oil in place. The 3,650 acre Project Area includes sixty 80-acre spaced wells in eleven inverted nine-spot patterns. Facilities process the 40 to 45 MMscf/D of miscible injectant which is then injected alternately with water on a 3 month/6 month gas/water cycle in eleven injection wells. An extensive surveillance program includes one fiberglass cased observation well, a comprehensive cased hole logging program, and radioactive gas tracers. The Project will program, and radioactive gas tracers. The Project will consist of WAG injecting a slug of more than 10% total pore volume (TPV) miscible gas. The miscible gas will pore volume (TPV) miscible gas. The miscible gas will be injected at a rate of approximately 1% TPV per year, followed by water injection to displace miscible gas through the reservoir and tertiary oil to producing wells. The estimated incremental-to-waterflood recovery is 5.5% of the original oil in place or 24 million barrels of oil. Introduction The Prudhoe Bay Sadlerochit (Permo-Triassic) reservoir located on the North Slope of Alaska (see Figure 1) contains over 22 billion stock tank barrels of oil and 40 trillion standard cubic feet of gas originally in place. The dominant recovery mechanism is gravity drainage place. The dominant recovery mechanism is gravity drainage supported by gas cap expansion. A waterflood has just been initiated which will ultimately be expanded to about 30% of the field. In August 1980, the Prudhoe Bay Unit (PBU) began evaluating the potential for enhanced oil recovery at Prudhoe. A task force composed of Unit members was formed to study this potential application. potential application. Process Selection Process Selection Four enhanced oil recovery categories were considered by the PBU: thermal processes, chemical flooding, enhanced waterflooding, and miscible flooding. The thermal processes, steam injection and in-situ combustion, were the easiest to eliminate from consideration. The average depth of the Sadlerochit is 9000 feet and current average reservoir pressure is 3850 psia. Steam injection recovery efficiencies would be low at these reservoir conditions. In-situ combustion would require high air injection pressures (5,000 to 6,000 psig) and ten to twenty acre well spacing. Berea core floods with Sadlerochit crude showed limited benefits from alkaline flooding. The acid number of Sadlerochit crude samples tested at 0.09 which is very marginal. Also, five different caustic compositions were evaluated with Sadlerochit crude for interfacial tension (IFT) values. The lowest IFT was 0.565 dynes/cm which is at least an order of magnitude too high to recover significant incremental oil over waterflood residual. Surfactant flooding initially appeared attractive for the Sadlerochit. However, one significant problem became apparent: injection of both low temperature Beaufort Sea water and higher temperature produced water would cause temperature and salinity gradients in the reservoir that would render current surfactants ineffective. Several schemes were devised to separate the two waters in the reservoir, but all were deemed uneconomical. Another obstacle was the high cost of providing chemicals at Prudhoe Bay. providing chemicals at Prudhoe Bay.

A field test of the depressuring process used to remobil ize and produce trapped gas from a watered-out reservoir is described.Actual performance is compared with predictions at two different points in time showing the modifications to the reservoir-aquifer simulation model that were required to obtain pressure matches.Increased water production rates, justified by the improved simulation model, led to the product ion of secondary recovery gas and, in turn, to the conclusion that the depressuring process is working.