《石油地质学 Petroleum Geology》课程教学资源（阅读文献）Piper Field-U.K. Outer Moray Firth Basin, North Sea.pdf

◆p|PER Figure 1B. Two-way time structure map of the Witch important exploration and appraisal wells. Contour Ground graben at base of the Cretaceous unconformity interval, 0. 2 m sec level, showing the locations of license blocks and offshore United Kingdom in 1969 in anticipation of as operator formed a consortium with Getty Oil a forthcoming licensing round by either the United International(England) Ltd, Allied Chemical(great Kingdom or Norway. at that time only one major Britain)ltd. and Thomson Scottish Associates. In oilfield, Ekofisk, had been discovered(Figure 1A). the period January-August 1971, more than 19,000 This offshore field produces from the Danian- line miles (30, 400 km) of seismic data in the U. K Maastrichtian Chalk(Figure 2) North Sea between 56 and 62N were evaluated with the knowledge of good source rock from the Occidental Group contracted for the building of a Kimmeridge Clay Formation, 500 mi(804 km)of spec semi-submersible rig that would be capable of winter seismic coverage of the Central graben was obtained. drilling in the northern North Sea. In addition, a drill This was subsequently traded for five other spec ship was contracted to take advantage of favorable shoots in the north Sea. One of these covered the summer weather should a license be awarded to the Outer Moray Firth basin and the area of the Consortium in the spring of 1972 of seismic data, the geophysicists and geologists were the U. K. 4th licensing round were submitted in able to make a structure map of the Central August 1971, and the Occidental group was granted graben, Outer Moray Firth basin, and the viking six blocks in March Three of these blocks Binterest intensified following the discovery of the Outer Moray Firth basin and each contained at least 4/19, 15/1l, and 15/17(Figure 1B)were in the Forties field in 1970(Figure 1A). This field produces one large feature with dip closure at the base of om Tertiary sandstones. By early 1971, it had Tertiary or the base of Cretaceous ecome apparent that the United Kingdom would be The Sonda i drillship spudded the 15/11-1 well he next to offer production licenses. As a result, (Figure 1B)in May 1972, a little more than one month work was concentrated on the U. K sector. Occidental after the block had been awarded. The primary target

Figure 16. Two-way time structure map of the Witch Ground graben at base of the Cretaceous unconformity level, showing the locations of license blocks and offshore United Kingdom in 1969 in anticipation of a forthcoming licensing round by either the United Kingdom or Norway. At that time only one major oilfield, Ekofisk, had been discovered (Figure 1A). This offshore field produces from the DanianMaastrichtian Chalk (Figure 2). From an initial interest in the onshore basins and with the knowledge of good source rock from the Kimmeridge Clay Formation, 500 mi (804 km) of spec seismic coverage of the Central graben was obtained. This was subsequently traded for five other spec shoots in the North Sea. One of these covered the Outer Moray Firth basin and the area of the subsequent Piper discovery. With 1500 mi (2400 km) of seismic data, the geophysicists and geologists were able to make a good structure map of the Central graben, Outer Moray Firth basin, and the Viking graben. Interest intensified following the discovery of the Forties field in 1970 (Figure 1A). This field produces from Tertiary sandstones. By early 1971, it had become apparent that the United Kingdom would be the next to offer production licenses. As a result, work was concentrated on the U.K. sector. Occidental important exploration and appraisal wells. Contour interval, 0.2 m sec. as operator formed a consortium with Getty Oil International (England) Ltd., Allied Chemical (Great Britain) Ltd., and Thomson Scottish Associates. In the period January-August 1971, more than 19,000 line miles (30,400 km) of seismic data in the U.K. North Sea between 56" and 62"N were evaluated. In July 1971, prior to license application, the Occidental Group contracted for the building of a semi-submersible rig that would be capable of winter drilling in the northern North Sea. In addition, a drill ship was contracted to take advantage of favorable summer weather should a license be awarded to the Consortium in the spring of 1972. Applications for petroleum production licenses in the U.K. 4th licensing round were submitted in August 1971, and the Occidental Group was granted six blocks in March 1972. Three of these blocks- 14/19, 15/11, and 15/17 (Figure lB)-were in the Outer Moray Firth basin and each contained at least one large feature with dip closure at the base of Tertiary or the base of Cretaceous. The Sonda 1 drillship spudded the 15/11-1 well (Figure 1B) in May 1972, a little more than one month after the block had been awarded. The primary target

as the tertiary, where sandstones were known to be productive in the Forties field. The well was the first to be drilled in the Outer Moray Firth basin and tested a large anticlinal structure mapped at the WITH IN base of the te It found sequence of Tertiary sandstones, Cretaceous chalks and Upper jurassic sandstones but encountered no After the 15/11-1, a well was drilled on a lar anticlinal feature in Block 14/19(Figure 1B). Again the Tertiary sandstones were the primary target. The 14/19.1 well encountered oil in thin sandstones of either the Jurassic or Lower Cretaceous and minor amounts of oil in tight Triassic sandstones. Oil was recovered by wireline test from two horizons in the Permian halibut bank formation dolomites The Sonda 1 then moved to block 15/17 to test CHALK MARKER another large structure. This well was planned to test the Upper Jurassic sandstones with the Tertiary sandstones as a secondary objective. The 15/17.1 had to be abandoned in September 1972 at 1500 ft(457 m), due to anchoring and shallow casing problems With the onset of wint eleased Discovery s The semi-submersible Ocean Victory arrived at the 1B and 3)in Novem 1972. This location is 0.5 mi(0.8 km)east and slightly downdip from the original 15/17-1 location. The location was moved downdip because of concern that the jurassic sandstones could be eroded from the crest of the structure as had already been seen in the 14, On 22 December 1972. the 15/17-1A well encoun SGIATH SANDSTOI tered 192 ft(58 m) of porous, permeable, oil-bearing sandstone of Late jurassic age between 7523 and 7729 ft( 2293 and 2356 m)subsea. In January 1973, the well produced 36 API low sulfur oil at 5266 BOPD through a 2-in. (5.08 cm)choke from 143 ft(44 m) of perforated zone between 7526 and 7693 ft(2294 魔 ED SHALE and 2345 m)subsea Post-Discovery HIN DOLOMITES Following the initial discovery well, an appraisal drilling program commenced in order to delineate the field. Three more wells, 15/17-2, -3, and-4, were drilled on the 15/17 block, and a bottom hole ontribution was made to the burmah 15/12-1 drilled just north of the 15/17 block boundary(Figure SHALES,COAiS F200 3). The 15/17-2 well, 1.6 mi (2.6 km)northwest of 15/17-1A encountered the same reservoir section as 15/17-1A between 7855 and 8114 ft(2394 and 2473 m)subsea Production testing was conducted through ooft. a2-in (5.08 cm) choke and flowed oil at rates of 15, 257 igure 2. Characteristic log response and thickness intervals 8074 to 8114 ft(2461 to 2473 m) subsea and 7942 to 8038 ft(2421 to 2450 m)subsea

SANDS wm INTERBEDDED SHALES _n SAND / SHALE CHALK MARKER CHALK MARL LIMESTONE ORGANIC SHALE PIPER SANDSTONE SGlATH P SANDSTONE SHALES, COALS. VOLCANICS - P RED SHALE ANHYDRITE WITH P THIN DOLOMITES SANDSTONE. SHALES. COALS 0 200 400 FT. Figure 2. Characteristic log response and thickness of formations in Piper field. was the Tertiary, where sandstones were known to be productive in the Forties field. The well was the first to be drilled in the Outer Moray Firth basin and tested a large anticlinal structure mapped at the base of the Tertiary. It found a relatively thick sequence of Tertiary sandstones, Cretaceous chalks, and Upper Jurassic sandstones but encountered no oil. After the 15/11-1, a well was drilled on a large anticlinal feature in Block 14/19 (Figure 1B). Again the Tertiary sandstones were the primary target. The 14/19-1 well encountered oil in thin sandstones of either the Jurassic or Lower Cretaceous and minor amounts of oil in tight Triassic sandstones. Oil was recovered by wireline test from two horizons in the Permian Halibut Bank Formation dolomites. The Sonda 1 then moved to Block 15/17 to test another large structure. This well was planned to test the Upper Jurassic sandstones with the Tertiary sandstones as a secondary objective. The 15/17-1 had to be abandoned in September 1972 at 1500 ft (457 m), due to anchoring and shallow casing problems. With the onset of winter weather, the drillship was released. Discovery The semi-submersible Ocean Victory arrived at the 15/17-1A location (Figures 1B and 3) in November 1972. This location is 0.5 mi (0.8 km) east and slightly downdip from the original 15/17-1 location. The location was moved downdip because of concern that the Jurassic sandstones could be eroded from the crest of the structure as had already been seen in the 14/ 19-1 well. On 22 December 1972, the 15/17-1A well encountered 192 ft (58 m) of porous, permeable, oil-bearing sandstone of Late Jurassic age between 7523 and 7729 ft (2293 and 2356 m) subsea. In January 1973, the well produced 36' API low sulfur oil at 5266 BOPD through a 2-in. (5.08 cm) choke from 143 ft (44 m) of perforated zone between 7526 and 7693 ft (2294 and 2345 m) subsea. Post -Discovery Following the initial discovery well, an appraisal drilling program commenced in order to delineate the field. Three more wells, 15/17-2, -3, and -4, were drilled on the 15/17 block, and a bottom hole contribution was made to the Burmah 15/12-1 well drilled just north of the 15/17 block boundary (Figure 3). The 15/17-2 well, 1.6 mi (2.6 km) northwest of 15/17-lA, encountered the same reservoir section as 15/17-1A between 7855 and 8114 ft (2394 and 2473 m) subsea. Production testing was conducted through a 2-in. (5.08 cm) choke and flowed oil at rates of 15,257 and 16,873 BOPD, respectively, from the perforated intervals 8074 to 8114 ft (2461 to 2473 m) subsea and 7942 to 8038 ft (2421 to 2450 m) subsea

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 has

0 - 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 sandstones. 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 oilwater 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 established 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 improvements 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