Combined ESP / Auto Gas Lift Completions in High GOR / High Sand Wells on the Australian Northwest Shelf

Abstract

Abstract The paper presents experience with an electric submersible pump (ESP) / auto gas lift completion design. The design has been developed to overcome the production engineering challenges which have been encountered following the commencement of production from the Stag oil field. The flow from the horizontal section of the wells has a high gas fraction, continuously slugs with a very short frequency, and carries large volumes of sand following the onset of water production. In addition, the reservoir pressure has depleted more rapidly than had originally been expected. These characteristics combine to represent one of the most challenging environments in which a field can be developed using ESP's. The paper describes the evolution of the completion design, which allows natural flow via either the tubing or the annulus, ESP lift via the tubing augmented by auto gas lift via the annulus, or conventional compressor-driven gas lift via the annulus. The measures taken to overcome poor ESP run life as a result of sand-laden slug flow are also described. Finally, operating experience with the improved completions is reviewed. The improved completion has been installed in six wells. In one well, a definitive incremental production rate of 1700 stb/d (60%) was achieved. The other wells are either new wells, or have had other remediation measures applied e.g. additional perforations. It can be demonstrated from their behaviour, though, that incremental production of 40-80% is the direct result of the improved completion design. In addition, ESP run life has been improved by more than 100%. Introduction The Stag oil field is located in 46 meters of water, 65 km north west of Dampier, Western Australia. It is expected that in excess of 40 million barrels of 19 API oil will be produced over the next 15 years. The reservoir, which is at a depth of ca. 680m below sea level and is ca. 20m thick, is a poorly consolidated Lower Cretaceous, M.australis glauconitic sandstone. Reservoir temperature is 125oF and oil viscosity at reservoir conditions is 7 cP. Well productivities are in the range 5-30 stb/d/psi. The field development plan anticipated using 5 ESP lifted horizontal production wells, with horizontal sections of up to 3000 ft. The wells were each expected to initially produce ca. 5000-6000 stb/d. There were also planned to be 3 water injection wells. There are currently 8 oil producing wells and 2 water injection wells located on a central production facility (CPF) which exports crude to a storage tanker, via a buoyant mooring system. A further 2 subsea water injection wells are tied back to the CPF. Following the commencement of production in May 1998 it became clear that the field had a larger than expected gas cap. As a consequence, the producing GOR's (now declining from an initial value in excess of 2000 scf/stb) were significantly higher than had been expected at the time the initial completion designs were developed. As the gas was produced, and because of a poorer than expected response from the edge drive aquifer, the reservoir pressure also fell more rapidly than had originally been expected. After 1 year of production the average reservoir pressure had fallen from ca. 1050 psi to ca. 700 psi. Consequently free gas fractions in excess of 80% have been common at pump suction conditions. The high gas fraction, in combination with horizontal section trajectories, has also caused terrain slugging in the wells. Finally, following the onset of water production in one of the wells, significant sand production commenced, which stabilised at ca. 0.1% volume (ca 870 lbs / 1000 bbls) over a period of several months.