Beatrice Field: Electrical Submersible Pump and Reservoir Performance 1981-83
Authors: Kilvington L.J. , Gallivan J.D. 
Published: December 2007

Summary
The Beatrice field is unique in the development of North Sea oilfields because production relies exclusively on artificial lift using electrical submersible pumps (ESP's)
Production started in Sept. 1981 from 3 wells and oil now is produced from 12 wells, each equipped with an ESP. Pressure maintenance is provided by 5 peripheral water injectors.
Wells are completed in two groups of reservoir zones-the upper and lower. The pump/packer combination is set deep, close to the pay . Two facilities for reservoir monitoring have been incorporated in the completion design: a permanent pressure and temperature gauge with continuous surface readout, and a wire line adaptor tool with bypass tubing to facilitate production logging.
Average pump installation life, excluding immediate failures, has been more than 6 months. Most failures have been associated with wells where the pump intake pressure has been below bubble point for an extended pressure has been below bubble point for an extended period. In the upper zones, where pressure maintenance period. In the upper zones, where pressure maintenance is satisfactory, average run duration (ARD) has been more than 9 months. By contrast, in the lower zones, which have been depleted by 1,300 psi (8963 kPa), ARD has been more than 5 months.
ESP's on Beatrice give satisfactory service pumping monophasic fluids. This is the normal condition for the field when pressure is maintained by water injection. Thus, diligent reservoir monitoring and management is needed to attain production targets.

Introduction
The Beatrice oilfield is located 12 miles (19 km) offshore Scotland in 150-ft (46-m) water depth in the Inner Moray Firth (Fig 1). The field was discovered in Aug. 1976 by Well 11/30–1. Six subsequent appraisal wells have delineated its extent over about 5,000 acres (20 × 10–6 m2). The development plan to recover oil by water flooding and artificial lift from two platforms was formulated and approved in 1978. Ten wells were predrilled from each platform before production began predrilled from each platform before production began from Beatrice A in Sept. 1981. Production from Beatrice B started in May 1984. Crude oil is transported by a 49-mile (79-m) long 16-in. (41-cm) pipeline to Nigg oil terminal in the Cromarty Firth (Fig. 1).

Reservoir Development
The structure is a southwest-northeast tilted fault block parallel to the trend of the Great Glen fault. It is closed parallel to the trend of the Great Glen fault. It is closed by a major fault to the southeast and dips at about 6 degs. toward the northwest (Fig. 2) encountering an oil/water contact at 6,784 for (2068 m) subsea. The sandstone reservoirs are contained in a sequence of about 1,000 ft (305 m) of Jurassic coastal sediments with a 30% net-to-gross ratio over the reservoir section. Fig. 3 shows a reservoir section with average formation parameters of the net sand in each zone. The uppermost zone, Zone 1A, has the best reservoir characteristics.
Table 1 summarizes reservoir conditions at datum (6,500 ft (1981 m) subsea) and average reservoir fluid characteristics. The low primary energy implied by these parameters means that water drive is essential to produce parameters means that water drive is essential to produce economically. The method chosen is a water injection scheme to supplement natural aquifer drive. Water flooding such a reservoir, consisting of vertically heterogeneous sand bodies and having a slightly adverse fluid mobility ratio, could be expected to lead to early water breakthrough. Since the field initially was pressured normally (0.45 psi/ft (10.18 kPa/m), high-water-cut wells would suffer dramatic loss of production. To overcome this problem and to increase the pressure drawdown available it was decided to equip each well with an ESP. Gas lifting was precluded by low gas availability throughout the field life.
For development purposes the reservoir zones are combined into two groups as shown in Fig. 3, with Zone 2 included in both groups because of its poor continuity. Each group has an independent peripheral water flood. The lower reservoir group is produced from Wells A1, A2, A3, A4, A6, A8, and A9 (lower injectors). The upper reservoir group is produced from Wells A-5, A7, A-11, A-12, and A1 (upper producers) with water injection through Wells A10, A13, and A16 (upper injectors). The well locations and functions are indicated in Fig. 2.
Before production startup, a reservoir study using a black-oil simulation model was carried out to estimate the ultimate recovery by water flooding. The recovery factors of the reservoir zones varied from 40% for Zone 1A to 8% for Zones 2 and 4. The simulation model was used to predict the oil and water injection rates required for pressure maintenance were estimated. pressure maintenance were estimated. JPT
P. 1934