Development and Operation of the El Gueria Reservoir, Ashtart Field, Offshore Tunisia

Abstract

Summary The Ashtart field is the second largest oil field in Tunisia, and maintaining a high level of production is important to the country's economy. The field's development is a good example of what can be accomplished through prudent operations and timely acquisition of reservoir and performance data. The analysis of these data has resulted in a better understanding of reservoir characteristics and field performance under pressure maintenance operations. This paper discusses the field performance history and the results of reservoir simulation studies designed to investigate means of achieving maximum oil recovery. The operational aspects of injecting seawater and artificial lifting of directional wells also are discussed. Performance data that were acquired after the projection of future performance are compared to predicted results. The performance are compared to predicted results. The geological and petrophysical characteristics of the reservoir rock are of interest because field case histories of nummulitic limestone reservoirs have not been reported in SPE literature. Introduction The Ashtart oil field is located in the Gulf of Gabes, 50 miles (81 Km] southeast of Sfax, Tunisia (Fig. 1). Water depths are about 223 ft [70 m] in the area of the field. Production operations are carried out by la Societe de Production operations are carried out by la Societe de Recherche et d'Exploitation des Petroles en Tunisie (SEREPT). Production is from a porous nummulitic limestone about 9,300 ft [2,835 m] deep. The field was discovered in Oct. 1971. Seventeen development wells have been drilled off a central platform. Two additional adjoining platform structures hold production, injection, and power-generation equipment, along with living facilities. The produced crude oil is piped to a 100,000-metric-ton [100 000-Mg] storage barge, and loading is provided through a buoyed terminal. Production began in 1974, and a water injection program was Production began in 1974, and a water injection program was initiated in late 1975 to arrest reservoir pressure decline. Field Development History The El Gueria limestone reservoir was discovered by the ASH-1 well in Oct, 1971 (see Fig. 2). Three additional delineation wells were drilled to help define the extent of the field: ASH-2, along the west flank, and ASH-N1 and ATH-1 at the northern and eastern extremities of the structure, respectively, Development drilling began from one centrally located platform in 1973. As of Jan. 1983, a total of 17 development wells (12 producers, 4 injectors, and 1 observation) had been drilled. The development wells are completed with 9%-in. [25-cm] casing cemented near the top of the reservoir with a 7-in. [18-cm] liner set through the producing interval. Most wells are equipped with 4 1/2-in. [11 -cm] tubing set on a packer. Two high-volume production wells and the four injectors are equipped with 7-in. [ 18-cm] tubing. Most of the wells flow naturally; however, two wells have been lifted by using downhole electrical submersible pumps ((ESP's). Although the ESP's have been successful in maintaining production, operating difficulties have arisen because of production, operating difficulties have arisen because of the rather high operating temperature and scaling tendency of the formation water. During 1982, compression equipment was installed, and gas lifting began in December. The injection water is filtered and treated seawater. Seawater is picked up about midway between the ocean floor and sea level, at a depth that minimizes both oxygen content and sediment. The water is filtered, and deoxygenated by vacuum de-aeration and chemical scavenging, and chemically treated for corrosion control. Maximum injection capacity is about 95,000 B/D [15 103 m 3/d] at 3,000-psi [20 684-kPa] discharge pressure. Before 1981, separation was two-stage, and because of the relatively high reservoir temperature and high well capacity, the first-stage separators were operated at about 210 deg. F [99 deg. C]. Since 1981, a heat exchanger that utilizes seawater for cooling has been used to lower the first-stage separator temperature to about 122 deg.F [50 deg. C], resulting in an increase of 6% in the total tank oil volume. Geology The Metlaoui formation in this field comprises three major limestone units. These units are illustrated in Fig. 3, which is a core log of a typical central well. The reservoir facies is about 260 ft [79 m] thick in the central part of the field, but it rapidly deteriorates to nonporous rock along the north, northwest, and southeast flanks of the structure. The limits of the porous facies were deduced from combination seismic studies, geological cross-section studies, and reservoir simulation. The reservoir rock is composed of fossil nummulites with varying amounts of spar cement and minor amounts of micrite. JPT P. 481