Captain Field Reservoir Development Planning and Horizontal Well Performance

Abstract

Abstract The Captain Field, in UK North Sea Block 13/22a, is an accumulation of viscous, high density oil which required a development plan utilizing only extended reach horizontal wells. Parallel field appraisal and facilities engineering required a close working team since during the period of 1992 to 1994 major changes occurred in the description of reservoir fluids. Oil viscosity decreased due to improvements in sampling methods which had significant impact on recommended design parameters. Other key data acquisition and field testing provided confidence in and a linking of relative permeability data and KvKh Fluid movement in the interwell region is dominated by gravity forces where up dip injected water slumps to bottom and water coning is a dominant feature. Well spacing of around 700-800 feet are planned. Significant water will be produced, and the cost of water handling is a primary consideration when designing well liquid flow rate. In Captain Field, the optimum well off take rate is found to be between 15,000 to 20,000 bpd. Development plans include a large waterflood to maintain reservoir pressure at high off take rates. The waterflood will utilize only horizontal water injectors wit11 'tuned' completions. Also, careful consideration of injector placement has taken into account potential future use for polymer flooding. Introduction The Captain Field is approximately 90 miles north-east of Aberdeen, Scotland in the UK Continental Shelf Block 13122a in 350 feet of water. The field was discovered in 1977 and it was clear that, although large with nearly 1,500 mmbbl oil in-place, economical extraction of the high density (19° API), viscous (88 cP) and low gas-oil ratio crude (Table 1) would not be easy. Also, the two primary reservoirs, the Upper andLower Captain Sands, are permeable but unconsolidated and of greatly varying thickness (0 - 275 ft). To this end no fewer than 20 appraisal wells (Fig. 1) were required to determine reservoir extent. Also, an extensive aquifer is present and underlies approximately 65% of the hydrocarbons. Not until performing a ten well appraisal program during 1993, which included a 90-day test of a field development prototype horizontal well, a vertical well water coning test, and further delineation drilling, was it clear that these technical challenges could be overcome. Conclusions from the 1993 appraisal program and subsequent reservoir simulation indicated that successful field development would require nearly 40 horizontal wells up to 6,000 ft long, artificial lift systems to deliver 15,000 bpd from each oil well producer, sand control completions, high temperature and high retention time fluid separation equipment to treat 60,000 bopd and 200,000 bwpd, and a single aquifer lift well to deliver 60,000 bwpd make up water for water flooding at full voidage replacement.