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 m 3 ] because of innovative reservoir management based on a comprehensive surveillance program and detailed reservoir description data. Infill drill wells have accounted for 76 X 10 6 bbl [12 X 10 6 m 3] of oil production. The mature waterflood was phased into a tertiary recovery project in 1981, and early performance is generally consistent with the planning study, which predicted that 47 X 10 6 bbl [7.5 X 10 6 m 3 ] of tertiary oil will be recovered.

Summary A comprehensive surveillance program and detailed reservoir description data were combined to provide innovative reservoir management for the Jay/Little Escambia Creek (LEC) waterflood. As a result of effective management, this waterflood has proved highly successful. Benefits of surveillance and data gathering have outweighed costs greatly. Introduction Following discovery of the Jay/LEC field Smackover reservoir in June 1970, an early decision was made by field operators to obtain extensive reservoir description data during field development. Consequently, 102 development wells were cored conventionally from 1970 to 1974. This resulted in the procurement of a wealth of reservoir rock data available for use in describing the reservoir to provide a basis for unitization and to plan and justify a waterflood project.1 During 1973, as planning for waterflood operations progressed, it became apparent that comprehensive surveillance was needed to complement the reservoir description data fully and, thereby, optimize recovery through effective reservoir management. A surveillance program was developed to monitor and control waterflood conformance in the thick-layered reservoir. Cased-hole logging tools along with pressure buildup and production tests are used extensively, in conjunction with permeability data from core analyses, to provide vertical conformance data. Areal conformance surveillance techniques employ radioactive tracers, reservoir pressure data, and interference tests. Use of surveillance information together with the reservoir description data yielded many new insights into water movement and zone depletion. Fluid movement analysis technique were developed, and several methods to improve recovery were defined. These include drilling, workovers, facility modifications, and injection balancing. These efforts have been responsible for maintaining field producing capability and delaying production decline until late 1979 and 75% of the estimated ultimate recoverable reserve had been produced. Field History The discovery well for the field, St. Regis No. 1, was completed in the Smackover formation in June 1970. A total of 102 wells was drilled on 160-acre (65-ha) well spacing during the development period from 1970 to 1974. Eighty-nine wells were producers, and 13 were dry holes. The Jay/LEC field was unitized on March 1, 1974, to implement a waterflood, and a 3:1 staggered line drive pattern was selected.2 Ultimate recovery expected is 346 million STB (55×106 stock-tank m3) or 47.5% of the 728 million STB (116×106 stock-tank m3) of original oil in place. This represents 222 million STB (35×106 stock-tank m3) more recovery than from primary operations. Water injection began on March 5, 1974. The basic operating plan was to open the entire productive section in both injection and production wellbores and, thereby, waterflood all Smackover zones simultaneously. Injection wells were acid fractured using large staged treatments to create connecting vertical fracture systems between spaced sets of perforations. In production wells, the entire productive section was opened without acid fracturing to maintain the flexibility to control future water production. The 3:1 line drive pattern has operated very successfully. The rapid reservoir pressure decline experienced during primary operations was arrested quickly, and maximum oil allowable rates were sustained.3

This paper discusses the application of data obtained from a field-wide conventional coring program in the Jay-Little Escambia Creek Unit. Benefits derived from the program far exceed the $5 million cost. Conventional coring of every well has proven the key factor for effective reservoir management of this major reserve. Introduction Early drilling and conventional coring in the Jay and Little Escambia Creek fields indicated that large oil deposits were contained in a thick, pressure depletion reservoir. Unitization and pressure maintenance would be necessary to increase the anticipated low primary recovery. To develop a basis for unitization and to plan the pressure maintenance program, a comprehensive pressure maintenance program, a comprehensive reservoir description was desirable. Field operators decided to expand early conventional coring field-wide to provide the necessary data. During development in 1970-74, 102 wells were drilled and cored conventionally through the Smackover carbonate formation. Average core recovery was 82%. Porosity and permeability were measured from more than 23,000 ft of core.Results of field-wide conventional coring were applied successfullyfor developing a basis for unitization,for planning the pressure maintenance program,for planning and evaluating well completion programs,for constructing a three-dimensional programs, (4) for constructing a three-dimensional reservoir description model,for analyzing and predicting waterflood behavior, andfor selecting infill-drilling well locations.A 12-well infill-drilling program began in 1977. Seven infill wells were drilled successfully and two drilling rigs now operate in the fields. Each well was cored conventionally to supplement reservoir description and to provide necessary data for optimum completion provide necessary data for optimum completion planning. Conventional coring continues for the rest of the planning. Conventional coring continues for the rest of the program. program. Field Description Jay Field is located in northwest Florida about 35 miles north o Pensacola. A small portion of this field extending into Alabama was named Little Escambia Creek. Jay Field was discovered by Exxon Co., U.S.A., in June 1970 and contained about 730 million STB of original oil in place.Oil accumulation in the Jay-Little Escambia Creek fields is located in the Smackover carbonate and Norphlet sand formations. Oil occurs mostly in the dolomitized portions of the Smackover carbonate. Fig. 1 is a structure portions of the Smackover carbonate. Fig. 1 is a structure map contoured on top of the Smackover formation. This formation is found slightly below 15,000 ft, and its average thickness is about 350 ft. The formation is layered with high permeability contrast among layers. Table 1 presents a summary of rock and fluid properties, presents a summary of rock and fluid properties, reservoir properties, and production-injection data for the field. Five operators were active during development from 1970-74: Exxon Co., U.S.A.; Louisiana Land and Exploration Co.; Chevron U.S.A., Inc.; Sun Co.; and Amerada-Hess Corp. After analyses of early drilling and conventional coring established the need for unitization and pressure maintenance, these operators decided to expand conventional coring field-wide. A total 102 wells eventually were drilled as the field was developed on 160-acre well spacing. JPT P. 1774

American Institute of Mining, Metallurgical, and Petroleum Engineers Inc. Abstract Pressure buildup tests are a valuable reservoir description and well evaluation tool in the Jay-Little Escambia Creek (Jay-LEC) Fields of Alabama and Florida. Four practical applications are demonstrated from the results of forty-three tests conducted to date. A comprehensive coring program coupled with high quality, consistent test data have made such applications possible. Buildup tests have provided the basis for arithmetic averaging of core provided the basis for arithmetic averaging of core data to determine effective reservoir permeability and are a significant guide in the permeability and are a significant guide in the planning and evaluation of workovers. Remedial planning and evaluation of workovers. Remedial action taken as a result of such tests will substantially improve waterflood conformance. These tests have also provided information that are an aid in the solution of reservoir description problems. Introduction This paper will briefly describe the test and interpretation procedures used by Exxon in the Jay-LEC Field and will demonstrate practical applications of test results to solve specific reservoir and production engineering problems. These applications were made as the field was developed, unitized, moved into a secondary recovery program, and underwent a major stimulation workover program. Specific demonstrated applications are:Buildup test permeability thickness values, correlated with those from core analysis data, provided the basis for arithmetically averaging core data to determine effective reservoir permeability. Well deliverabilities were predicted, and two reservoir models were constructed utilizing these data.Horizontal barriers to vertical flow were determined to exist in massive Smackoverpay sections. As a result, workover planning and implementation was significantly influenced.Buildup tests were used to determine the need for well stimulation to open total pay section and to evaluate the effectiveness of workovers which were designed to accomplish this objective.Reservoir limits, as defined by geological interpretation, were confirmed by buildup tests. The Jay Field was discovered in Northwest Florida during June 1970 when the St. Regis No. 1 well penetrated the Smackover Formation. Further drilling expanded field limits into Alabama, and development of this (15,500 feet) deep reservoir proceeded rapidly on 160-acre spacing. The Alabama portion of this common reservoir was designated as the Little Escambia Creek Field. During development, a comprehensive data gathering program was maintained. Each well, in addition to being logged with gamma ray, resistivity and porosity tools, was conventionally cored through the Smackover and Norphlet pay zones with core recovery averaging 82 pay zones with core recovery averaging 82 percent. percent.