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Abstract

Gas lift wells producing from a subsea template placed 12 km away from the processing facilities is known to be very challenging. Long pipelines give large volumes of gas and fluid which may influence each other, causing slugging or pressure variations in production pipelines and pressure fluctuations in the gas lift line. This again creates variations in rates and pressure into the process plant. Gas lift is the preferred artificial lifting method in subsea completed wells, due to the roboustness.The Yme Beta Øst subsea wells were put on production in the summer of 1996. Following a period of natural production the gas lift was started March 97. Immediately after start up of the gas lift heavy slugging in the system, both subsea and in process units was observed. As a result of the slugging the process was frequently shut down due to the pressure and rate variations. To reduce the slugging the wells were choked back, leading to reduced production. The slugging was investigated and the reason for the slugging was found to be in the production pipelines. The varying pipeline pressure influenced the gas lift system in the wells. In order to reduce this, a new gas lift design was carried out and new gas lift valves installed in one of the Yme Beta Øst wells and later both Beta Vest wells.

Introduction

The marginal oil field Yme was put on production in February 1996. The field was produced for over five years until the production was shut down April 2001. The field had then produced over 8 MSm³, including about 2.5 MSm³ from the subsea gas lift field Beta. See Figure 1.

The Yme oil field was discovered by exploration well 9/2-1 in the Yme Gamma Vest structure in 1987. The field is located in the southern part of the North Sea, approximately 100 km from the Norwegian coast and 130 km from the nearest offshore installation, see Figure 1. The water depth in the area is 92 m. The discovery in the main field was small and further exploration drilling was performed in order to increase the reserve basis for a field development. The next well 9/2-2 was dry, whereas well 9/2-3 made another small discovery in the Yme Beta Øst structure, located 12 km from the main field. The total STOOIP were estimated to 44.8 MSm³, with a recovery of approximately 18%. The recovery factor is low due to short production period and a high volume percent of the oil placed in relatively low permeable sands.

Due to a slightly over pressurised reservoir pressure and relative low GOR, 50 Sm³/Sm³, artificial lift were required in all the Yme wells. Electrical submersible pumps (ESP) were installed in the platform wells whereas gas lift was installed in the subsea wells. Subsea gas lift were chosen due to its simplicity and probability for less maintenance compared with other artificial lift methods. ESP's were also chosen due to the limitations in gas processing capacity on the platform and availability of gas in the system after production shut downs.

The distant location of the field required on site processing, oil export facilities and handling of excessive produced gas. Together with the small reserve basis this resulted in a marginal field economy. The development is shown in Figure 2 with the Yme Beta pipelines, storage tanker and production platform.