Abstract

This paper describes the use of electrical submersible pumps (ESPs) for the enhancement of water injection on the BP operated Ula platform, situated in the Norwegian sector of the North Sea. The pumping scheme was designed to use off-the-shelf pumping equipment, in a manner not normally used in the offshore North Sea environment, to meet the requirements of rapid installation, minimum use of valuable deck space, high suction pressures and a high degree of safety in operation. Taking suction from the existing water injection manifold at 220 barg, two pumps in parallel were required to boost the injection pressure in two wells to 330 barg, and achieve a total injection rate of 25,000 bpd (3,975 m3/d).

To cope with the high suction pressure each ESP was housed in a suction can, capable of taking the full suction pressure, constructed mainly from off-the-shelf standard well casing. The pump/can units, each around 35 metres long, were installed in spare pump/can units, each around 35 metres long, were installed in spare well conductors, resulting in minimum use of deck space.

The pump system was in operation for 9 months until the permanent uprated water injection system was commissioned.

Introduction

The water injection system on Ula was designed to inject 120,000 bpd (19,080 m3/d) of seawater at a wellhead manifold pressure of 214 barg. Design plateau oil production rate was 74,000 stbpd (11,765 m3/d). Within the first year this plateau rate was increased to 94,000 stbpd (14,945 m3/d). The present target average production rate is now 110,000 stbpd (17,489 m3/d), which can be achieved with high plant uptime. The original plant design capacity was 100,000 stbpd (15,900 m3/d) (based on tanker loading) but operating experience, throughput tests and further design checks have shown the plant capable of 113,000 stbpd (17960 m3/d). Reservoir monitoring and geological studies have seen the reserves rise from 160 mmstb to 435 mmstb consistent with the revised plateau rates. plateau rates. In order to sustain the higher plateau rate and production rates, later in field life, it became rapidly evident that there was a need to increase the water injection rate. Reservoir studies not only indicated the need for sustained long term injection but a need for an immediate increase in injection rates. some injection wells had not achieved the predicted rates, for the design injection pressure. It was realised that to meet the increased injection rate requirement, a substantial increase in injection pressure was required. The injection system would have to be pressure was required. The injection system would have to be uprated to 180,000 bpd (28,618 m3/d) from 120,000 bpd (19,080 m3/d) with an injection manifold pressure of 330 barg. The original injection pressure was 220 barg. Following economic assessment, based on reservoir simulations, the uprating project was approved and a project team was established with an estimated project timetable in excess of one year.

The need for an immediate increase in injection rate also had to be fulfilled.

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