Detailed seismic coverage was shot after the initial 15/1 discovery. This resulted in a spacing between seismic nes of approximately 2460 ft(750 m). The data OXY her with the new veloci nd geological data rom the appraisal wells, helped to define the field limits, and a single production platform was planned Faults of varying displacement were mapped within the field limits and some of these faults offset the reservoi considered necessary to drill further appraisal wells to determine if the oil-water contact was the same for the entire field and if the faults were likely to ffect production. At time, field limits would be more precisely defined and would allow for placement of the production platform Wells 15/17-5 and 15/176 confirmed that the Piper field could be fully developed from one centrally located platform. Both 17-4(8510 ft subs 17-7 well was drilled to the south fault (now designated the"A"fault)in late 1973. The Jurassic sandstones were present but significantly deeper and only partially filled, with an oil -water contact at 9200 ft(2804 m)subsea The discovery and appraisal program had estab lished an oil column of approximately 1200 ft (366 m)within a layered reservoir(figure 5)covering an area of 7350 ac (29.75 km2)and containing 1. 4 billion ● PRODUCTION WELL III PIPER SAND ABSENT STBOIIP. A single steel platform containing 36 well △| NJECTION WELL EROSIONAL EDGE slots was centrally located over the field in 474 ft (144 m)of water in June 1975 and made ready for PRODUCTION WELL roduction drilling by October 1976 ◆ APPRAISAL WELL Contour Intervol 200 F1 The Pl production well was spudded on 10 October 1976 and established commercial production on 7 December 1976 at more than 30,000 BOPD, restricted Figure 3. Top Piper sandstone depth re map by 5v2-in. (14 cm)tubing. Development progressed of Piper field. o, type logs shown by Fi A and steadily, and the P7 well was completed in April 1977 5B,wels15/17P2and15/17P14.*,co os and producing more than 50,000 BOPD restricted by 7- thin sections, Figures 17, 18, and 19 for wells 15/17. in. (17. 8 cm)tubing(Figure 3) 6, 15/17-7, and 15/17-P32. t, log porosity vs. core From field characteristics, nearby well data, and porosity and permeability, Figures 20 and 21, wells 15/ the availability of accurate pressure data, it was 17-5 and 15/17-8; also gamma ray-dual lateralog from apparent that natural water influx was occurring well 15/17-P32, Figure 22 in Piper field. This aquifer drive was calculated by material balance to be approximately 250,000 bbl/d By mid- 1977, it was obvious that reservoir pressure could not be sufficiently maintained with natural The 15/173 well was drilled on the downthrown water influx at projected reservoir production rates side of a normal fault 1. 4 mi(2.2 km)south of 15/ of 250,000 to 300,000 BOPD. In late 1977, the first 17-1A. This well found the same Jurassic sandstones injection wells, P16 and P17, were drilled to between 8131 and 8246 ft(2478 and 2537 m)subsea. supplement the natural water influx, and injection It was production tested through a 2-in. (5.08 cm) commenced in early 1978(Figure 3). These and choke from the intervals 8131 to 8211 and 8228 to subsequent injectors halted the decline in reservoir 8243 ft(2478 to 2503 and 2508 to 2512 m)subsea pressure as production rates greater than 300,000 at a rate of 15, 509 BOPD. The upper part of the boPd were sustained( figure 6) Jurassic sandstone in this well was missing In 1980, following a formal request to the U. K circumstance interpreted to be the result of late government, the field rate was reduced to allow for Jurassic or early Cretaceous erosion selective completion and injection and more efficient The 15/12-1 well was then drilled by the burmah reservoir management( Figure 6). Further improve- Group It encountered thick, wet reservoir sand- ments in recovery were also made following the stones. The 15/17-4 well was then drilled updip of installation of a gas lift system in 1977 and high 15/121 and established an oil-water contact at 8510 volume submersible pumps in 1982. Selective ft(2594 m) subsea completion of both injectors and producing wells has0 - 1 Krn 0 1 Mile PRODUCTION WELL UU PIPER SAND ABSENT A INJECTION WELL - EROSIONAL EDGE ABANDONED KIMMERIDGE SHALE PRODUCTION WELL Contour lntervol = 200 Ft + APPRAISAL WELL @ FAULT NAME Figure 3. Top Piper sandstone depth structure map of Piper field. 0, type logs shown by Figures 5A and 58, wells 1511 7-P2 and 1511 7-PI 4. *, core photos and thin sections, Figures 17, 18, and 19 for wells 1511 7- 6, 1511 7-7, and 1511 7-P32. t, log porosity vs. core porosity and permeability, Figures 20 and 21, wells 151 17-5 and 1511 7-8; also gamma ray-dual lateralog from well 1511 7-P32, Figure 22. The 15/17-3 well was drilled on the downthrown side of a normal fault 1.4 mi (2.2 km) south of 15/ 17-1A. This well found the same Jurassic sandstones between 8131 and 8246 ft (2478 and 2537 m) subsea. It was production tested through a 2-in. (5.08 cm) choke from the intervals 8131 to 8211 and 8228 to 8243 ft (2478 to 2503 and 2508 to 2512 m) subsea at a rate of 15,509 BOPD. The upper part of the Jurassic sandstone in this well was missing, a circumstance interpreted to be the result of Late Jurassic or Early Cretaceous erosion. The 15/12-1 well was then drilled by the Burmah Group. It encountered thick, wet reservoir sand￾stones. The 15/17-4 well was then drilled updip of 15/12-1 and established an oil-water contact at 8510 ft (2594 m) subsea. Detailed seismic coverage was shot after the initial discovery. This resulted in a spacing between seismic lines of approximately 2460 ft (750 m). The data, together with the new velocity and geological data from the appraisal wells, helped to define the field limits, and a single production platform was planned. Faults of varying displacement were mapped within the field limits, and some of these faults offset the reservoir sands (Figure 4). It was therefore considered necessary to drill further appraisal wells to determine if the oil-water contact was the same for the entire field and if the faults were likely to affect production. At the same time, field limits would be more precisely defined and would allow for better placement of the production platform. Wells 15/17-5 and 15/17-6 confirmed that the Piper field could be fully developed from one centrally located platform. Both encountered the same oil￾water contact as 15/17-4 (8510 ft subsea). The 15/ 17-7 well was drilled to the southwest and across a major fault (now designated the "A" fault) in late 1973. The Jurassic sandstones were present but significantly deeper and only partially filled, with an oil-water contact at 9200 ft (2804 m) subsea. The discovery and appraisal program had estab￾lished an oil column of approximately 1200 ft (366 m) within a layered reservoir (Figure 5) covering an area of 7350 ac (29.75 km2) and containing 1.4 billion STBOIIP. A single steel platform containing 36 well slots was centrally located over the field in 474 ft (144 m) of water in June 1975 and made ready for production drilling by October 1976. The P1 production well was spudded on 10 October 1976 and established commercial production on 7 December 1976 at more than 30,000 BOPD, restricted by 5%-in. (14 cm) tubing. Development progressed steadily, and the P7 well was completed in April 1977 producing more than 50,000 BOPD restricted by 7- in. (17.8 cm) tubing (Figure 3). From field characteristics, nearby well data, and the availability of accurate pressure data, it was apparent that natural water influx was occurring in Piper field. This aquifer drive was calculated by material balance to be approximately 250,000 bbl/d. By mid-1977, it was obvious that reservoir pressure could not be sufficiently maintained with natural water influx at projected reservoir production rates of 250,000 to 300,000 BOPD. In late 1977, the first injection wells, P16 and P17, were drilled to supplement the natural water influx, and injection commenced in early 1978 (Figure 3). These and subsequent injectors halted the decline in reservoir pressure as production rates greater than 300,000 BOPD were sustained (Figure 6). In 1980, following a formal request to the U.K. government, the field rate was reduced to allow for selective completion and injection and more efficient reservoir management (Figure 6). Further improve￾ments in recovery were also made following the installation of a gas lift system in 1977 and high volume, submersible pumps in 1982. Selective completion of both injectors and producing wells has