《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

Piper field-UK Outer moray Firth Basin, North Sea CONRAD E. MAHER IGGE-SIRS Ltd Aberdeen Scotland H. RICHARD H SCHMITT Occidental International Exploration and Production Company Bakersfield, California SIMON C H GREEN Occidental Petroleum(Caledonia) Ltd Aberdeen, Scotland FIELD CLASSIFICATION basIN: North Sea RESERVOIR AGE: Jurassic BASIN TYPE: Rift PETROLEUM TY RESERVOIR ROCK TYPE: Sandstone TRAP TYPE: Tilted Fault Block RESERVOIR ENVIRONMENT OF DEPOSITION: Nearshore to Shallow Marine LOCATION The piper field is in U. K. North Sea block 15/17 0 50 Miles 110 mi (177 km) northeast of Aberdeen, Scotland (Figures lA and 1B ). It is situated on a shelf on the northern margin of the witch Ground graben (WGg in the Outer Moray Firth basin(Figure 1B). The WGG is a northwesterly trending graben that developed in the late jurassic, branching off from the intersection of the north-south-trending viking and Central grabens, 50 mi( 80 km)southeast of Piper (Figure lA Nearby oil fields include Claymore, Tartan, Scap Highlander, Scott, Galley, Petronella, Chanter, Rob Roy, and Ivanhoe. These fields have Upper Jurassic sandstone reservoirs except for Scapa, which produces from Lower Cretaceous sandstones. The Claymore field also produces from Lower Cretaceous sandstones The Piper field is ranked number 271 among the worlds giant fields( Carmalt and St John, 1986), and its ultimate recovery will be almost 1 billion bbl of HISTORY ● Oil Fiald Pre-Discovery Figure 1A. the location of Piper and other fields in the Central, Viking, and Witch Ground grabens of the Occidental began regional seismic and geological North Sea, showing national sectors. DM, Denmark; studies of the petroleum potential of the onshore and DU, Germany: ND, Netherlands

Piper Field-U.K. Outer Moray Firth Basin, North Sea CONRAD E. MAHER IGGE-SIRS Ltd. Aberdeen, Scotland H. RICHARD H. SCHMITT Occidental International Exploration and Production Company Bakersfield, California SIMON C. H. GREEN Occidental Petroleum (Caledonia) Ltd. Aberdeen, Scotland FIELD CLASSIFICATION BASIN: North Sea RESERVOIR AGE: Jurassic BASIN TYPE: Rift PETROLEUM TYPE: Oil RESERVOIR ROCK TYPE: Sandstone TRAP TYPE: Tilted Fault Block RESERVOIR ENVIRONMENT OF DEPOSITION: Nearshore to Shallow Marine LOCATION The Piper field is in U.K. North Sea Block 15/17, 110 mi (177 km) northeast of Aberdeen, Scotland (Figures 1A and 1B). It is situated on a shelf on the northern margin of the Witch Ground graben (WGG) in the Outer Moray Firth basin (Figure 1B). The WGG is a northwesterly trending graben that developed in the Late Jurassic, branching off from the intersection of the north-south-trending Viking and Central grabens, 50 mi (80 km) southeast of Piper (Figure 1A). Nearby oil fields include Claymore, Tartan, Scapa, Highlander, Scott, Galley, Petronella, Chanter, Rob Roy, and Ivanhoe. These fields have Upper Jurassic sandstone reservoirs except for Scapa, which produces from Lower Cretaceous sandstones. The Claymore field also produces from Lower Cretaceous sandstones. The Piper field is ranked number 271 among the world's giant fields (Carmalt and St. John, 1986), and its ultimate recovery will be almost 1 billion bbl of oil and gas liquids. HISTORY Pre -Discovery Figure 1A. The location of Piper and other fields in the Central, Viking, and Witch Ground grabens of the Occidental began regional seismic and geological North Sea, showing national sectors. DM, Denmark; studies of the petroleum potential of the onshore and DU, Germany; ND, Netherlands

◆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 Danian￾Maastrichtian 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 encoun￾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 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 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

A BLOCK Il-l LOCK IA A 15/17-7 P2815/17-4P1 15/12 6500 MAASTRICH TIA ORIGIHAL O.w. C.-+200 M DDIt 9500 鼎L5CALE ZECHSTEIN TRIASSIC Figure 4. Structural cross section running southwest- northeasterly fault block rotation and the structural northeast through Piper field, demonstrating the configuration. See Figure 3 for location GR. API LLD GR, AP LLD, am KIMMERIDGE CLAY KIMMERIDGE CLAY 、~°。NE76 50F7 M-AsECAJH (gor f PENTLAND Figure 5.(A) and (B)show type logs for wells 15/17- of the Piper field, respectively. (See Figure 3 for well and 15/17-P1 4 for the western and eastern areas locations. been practiced in order to balance the natural influx recovery to an accepted figure of 952 MMBO and injected water with offtake from each layer Production exceeded 800 MMBO on 25 October 1987 within the reservoir. The combination of these and the field was still producing at a rate of 120,000 management techniques is expected to lead to a boPd at the time of the disaster on 6 July Initial ultimate recovery for the Piper field was platform in mid-les uled to resume from a recovery factor of approximately 70% Production is schedt put at 618 MMBO, but subsequent reservoir The discovery of Piper encouraged further drilling formance confirmed this to be conservative. There activity in the Outer Moray Firth area leading to has been a steady increase in the estimated ultimate the discovery of the Claymore, Tartan, Scott

-9500 - - TRIASSIC 10500 - Figure 4. Structural cross section running southwest￾northeast through Piper field, demonstrating the GR, API LLD , nrn 0 100 0.2 1 10 100 I000 2000 /I I KIMMERIDGE CLAY Figure 5. (A) and (B) show type logs for wells 15117- P2 and 1511 7-PI 4 for the western and eastern areas been practiced in order to balance the natural influx and injected water with offtake from each layer within the reservoir. The combination of these management techniques is expected to lead to a recovery factor of approximately 70%. Initial ultimate recovery for the Piper field was put at 618 MMBO, but subsequent reservoir performance confirmed this to be conservative. There has been a steady increase in the estimated ultimate - -9500 HORIZONTAL SCALE - 1 Km 0 1 M!Ie VERTICAL EXAG i 5 - -10500 northeasterly fault block rotation and the structural configuration. See Figure 3 for location. GR, API LLD , nm 0 100 0.2 1 10 100 1000 2000 KIMMERIDGE CLAY TOP PIPER SANDSTONE (- 77667 - I - of the Piper field, respectively. (See Figure 3 for well locations.) recovery to an accepted figure of 952 MMBO. Production exceeded 800 MMBO on 25 October 1987, and the field was still producing at a rate of 120,000 BOPD at the time of the disaster on 6 July 1988. Production is scheduled to resume from a new platform in mid-1992. The discovery of Piper encouraged further drilling activity in the Outer Moray Firth area leading to the discovery of the Claymore, Tartan, Scott

Viking graben. Instead the virgin Outer moray Firth EFFICIENT RESERVOIR MANAGEMEN basin blocks were nominated as their first choice VALNTENANCE SHUTDOWN As explained above, following the successful 250 application for the acreage the initial two wells drilled in this virgin basin, 15/11-1 and 14/19-1, had Tertiary sandstones as their primary objective with the integration of the results of these wells, the primary objective of the Piper discovery well, 15 17-1A, were Upper Jurassic sandstones PLATFORM REPA RS Now 6770798a118384858678 With todays exploration methods, Piper field would be easily mapped and discovered. Since the discovery of the Piper field, the industry has become WATER INJECT very much more knowledgeable about extension-type Figure 6. Graph showing Piper fields performance basins and the stratigraphy, origin, migration, and story,1976-1988Production averaged over 250.000 entrapment of oil and gas within them It would be easy to map Piper-type structures and BOPD for the first three years but had declined to approximately 120,000 BOPD by mid-1988, 62% available, to recognize that the reservoir sandstone watercut, at the time of the disaster. Water production and caprocks are present. It still is not possible to exceeded oil production in 1987. tell which undrilled structures contain oil or gas Today, Occidental's first choice structure in block ill might be drilled first, as it was in 1972, and be found dry Although not definitely proven by Petronella, Highlander, Scapa, Rob Roy, Ivanhoe and the 15/11 structure is dry because it remained too Chanter fields. Several additional discoveries have high during the Cretaceous. Consequently, the Piper yet to be declared commercial Figure 1B) sandstones we slapped by the maastrichtian chalk, which is not a caprock in this area. Indeed the chalk came to within a few feet of onlappir the sandstone at Piper, in which case the Pipe DISCOVERY METHOD structure would also have been dry Prior to the application for acreage that contains STRUCTURE the Piper field, the Occidental exploration team had 30. 400 km) of seismic data covering large areas of Tectonic History the U. K northern North Sea. The prospectivity of The North Sea and northwest Europe were part this region was considered to be good, based on the of the landmass until the late Permian(Ramsbottom knowledge of existing source rocks and reservoir 1978). At this time a shallow epicontinental gulf sandstones cropping out onshore and on the fact that covered most of the north sea basin area and resulted two large fields had already been discovered (Ekofisk in widespread evaporite deposition In the southern and Forties). A Mesozoic discovery that turned out North Sea, thick salt deposits of the halibut Bank to be the brent field was also rumored (Figure 1A). Formation(Zechstein) were laid down. In the pipe A large number of potentially prospective struc- area, 100 ft (30 m) of interbedded dolomite and tures were mapped within the U. K. 4th Round anhydrite containing an acreage. Seismic data quality was good, and it was Permian palynomorphs were overlain by 300 ft( 91 a reasonable assumption that nearly every operator m)of massive anhydrite containing a few dolomite he United Kingdom had comparable structural beds up to 20 ft(6 m)thick(figure 2 interpretations. However, some of the major oil The halibut Bank Formation overlies a thick companies had the advantage of having already sequence of Lower to Middle Carboniferous sand drilled wells through the Mesozoic sandstones and stones and shales It in turn is overlain by extensive had good data on reservoir quality, source rock, and sections of nonmarine shale and claystone of Triassic caprock. a key point in the Occidental Group' s age. Drilling in the Claymore field has confirmed cquisition strategy was therefore to avoid head-on structural movement on northwest-southeast competition with other larger and more knowledge. trending faults during the deposition of the triassic able operators for the structures in the northern In the piper area, the triassic red shales are overlain

RATE REDUCTION FOR MORE EFFICIENT RESERVOIR MANAGEMENT MAINTENkNCE SHUTDOWN PLATFORM REP 76 ( 77 1 78 1 79 1 80 1 81 1 82 1 83 1 84 1 85 1 86 1 87 1 86 YEAR - OIL PROD. --- WATER PROD -- WATER INJECT Figure 6. Graph showing Piper field's performance history, 1976-1 988. Production averaged over 250,000 BOPD for the first three years but had declined to approximately 120,000 BOPD by mid-1 988, 62% watercut, at the time of the disaster. Water production exceeded oil production in 1987. Petronella, Highlander, Scapa, Rob Roy, Ivanhoe, and Chanter fields. Several additional discoveries have yet to be declared commercial (Figure 1B). DISCOVERY METHOD Then Prior to the application for acreage that contains the Piper field, the Occidental exploration team had acquired and interpreted over 19,000 line miles (30,400 km) of seismic data covering large areas of the U.K. northern North Sea. The prospectivity of this region was considered to be good, based on the knowledge of existing source rocks and reservoir sandstones cropping out onshore and on the fact that two large fields had already been discovered (Ekofisk and Forties). A Mesozoic discovery that turned out to be the Brent field was also rumored (Figure 1A). A large number of potentially prospective struc￾tures were mapped within the U.K. 4th Round acreage. Seismic data quality was good, and it was a reasonable assumption that nearly every operator in the United Kingdom had comparable structural interpretations. However, some of the major oil companies had the advantage of having already drilled wells through the Mesozoic sandstones and had good data on reservoir quality, source rock, and caprock. A key point in the Occidental Group's acquisition strategy was therefore to avoid head-on competition with other larger and more knowledge￾able operators for the structures in the Northern Viking graben. Instead, the virgin Outer Moray Firth basin blocks were nominated as their first choice. As explained above, following the successful application for the acreage, the initial two wells drilled in this virgin basin, 15/11-1 and 14/19-1, had Tertiary sandstones as their primary objective. With the integration of the results of these wells, the primary objective of the Piper discovery well, 15/ 17-lA, were Upper Jurassic sandstones. Now With today's exploration methods, Piper field would be easily mapped and discovered. Since the discovery of the Piper field, the industry has become very much more knowledgeable about extension-type basins and the stratigraphy, origin, migration, and entrapment of oil and gas within them. It would be easy to map Piper-type structures and, perhaps, with the quality of the seismic data available, to recognize that the reservoir sandstone and caprocks are present. It still is not possible to tell which undrilled structures contain oil or gas. Today, Occidental's first choice structure in block 15/11 still might be drilled first, as it was in 1972, and be found dry. Although not definitely proven by the three wells on this block, it is now thought that the 15/11 structure is dry because it remained too high during the Cretaceous. Consequently, the Piper sandstones were onlapped by the Maastrichtian chalk, which is not a caprock in this area. Indeed, the chalk came to within a few feet of onlapping the sandstone at Piper, in which case the Piper structure would also have been dry. STRUCTURE Tectonic History The North Sea and northwest Europe were part of the landmass until the late Permian (Ramsbottom, 1978). At this time, a shallow epicontinental gulf covered most of the North Sea basin area and resulted in widespread evaporite deposition. In the southern North Sea, thick salt deposits of the Halibut Bank Formation (Zechstein) were laid down. In the Piper area, 100 ft (30 m) of interbedded dolomite and anhydrite containing an assemblage of Upper Permian palynomorphs were overlain by 300 ft (91 m) of massive anhydrite containing a few dolomite beds up to 20 ft (6 m) thick (Figure 2). The Halibut Bank Formation overlies a thick sequence of Lower to Middle Carboniferous sand￾stones and shales. It in turn is overlain by extensive sections of nonmarine shale and claystone of Triassic age. Drilling in the Claymore field has confirmed structural movement on northwest-southeast￾trending faults during the deposition of the Triassic. In the Piper area, the Triassic red shales are overlain

by a nonmarine sequence of siltstones, shales, Local Structure lignites, tuffs, and basalt flows with occasional thin The Piper field lies on the northern margin of the bedded freshwater limestones of Middle Jurassic age. WGG. Four significant faults are present within the In the Claymore area, and possibly the piper area of the Triassic was marke ked by a period of Piper field(Figures 3 and 8). Most of the fault erosion. Middle Jurassic sediments in the Piper area movement occurred after the deposition of the Piper basin and deposition of the widespread, lower deltaic was syndepositional. The field comprises three major plain sediments of the Sgiath Formation (Maher and tilted fault blocks, dipping gently to the northeast There was a major transgression in the late axis. The main Piper field(blocks IA and beest Harker, 1987 and slightly folded along the northeast-southwe Oxfordian over the whole of the Outer Moray Firth at about 8 to the northeast(Figures 3, 4, and 9) basin area. This is represented by the"i shale"in the Piper field(Figure 5). Following this transgres sion, the shallow marine Piper sandstones were deposited STRATIGRAPHY After the deposition of the Piper sandstones, there was major extension and extensive deepening of the The oldest sediments penetrated in Piper field are Witch Ground graben(WGG). The graben had been Lower Carboniferous Coal Measures of the Forth initiated as early as Triassic times and subsidence Formation( Figures 2 and 10). They comprise a thinly and tilting occurred during the deposition of the Piper interbedded deltaic sequence of sands, shales, and and Sgiath sandstones. Consequently, wells within coals. Upper Permian sediments, which unconform the graben have thicker Piper and Sgiath sandstone ably overlie the Carboniferous, represent evaporite sections than do wells on the northern margin of deposits of the Zechstein sea. Fluvio- lacustrine of shelf areas away from the graben margin resulted red beds of the smith Bank Formation. No Lower in erosion of Piper and Sgiath sandstones along fault Jurassic rocks are present due to nondeposition or scarps and the graben margin These sediments were erosion. The middle jurassic consists of Rattray bably redeposited as gravity flows within the Formation volcanics and Pentland Formation alluvia to marginal- marine argillaceous clastics and coals extension occurred, accompanied by a widespread bedded sands, shales, and coals of the paralic Sgiath transgression that deposited the organic-rich shales Formation were overlain by shallow marine sands of the Kimmeridge Clay Formation over the Outer and shales of the Piper Formation. These in turn Moray Firth basin area. The Piper structure were overlain by anoxic marine shales of the a result of fault block rotation and a fall in sea level brought to a close during the early cretaceous when This resulted in local erosion of Jurassic sediments sandy marls and limestones of the valhall Formation and nondeposition of Cretaceous sediments. Only a onlapped the Piper structure Diminishing tectonic thin, " condensed"sequence of Lower Cretaceous activity into the late Cretaceous was marked by deposits is present in the Piper field postrift hemipelagic deposition of marls, limestones During the Late Cretaceous, regional subsidence and chalks. Clastic sedimentation returned in the and a rise in sea level resulted in the progressive Tertiary, represented by a thick sequence of sands onlap of the Piper structure by marls and chalks of and shales Santonian, Campanian, and Maastrichtian age The Piper reservoir is composed of two formations Figure 4). By the end of the Cretaceous, tectonic within the Upper Jurassic Humber Group these are movements had largely ceased and a thick sequence the Oxfordian Sgiath Formation(harker et al., 1987) of Tertiary sands and clays was deposited throughout and the Upper Oxfordian to Kimmeridgian Piper the area. The burial history of the Piper reservoir Formation (Deegan and Skull, 1977)(Figure 10) s summarized in Figure 7. Originally the section now assigned to the Sgiath Formation was dated as Callovian(Maher, 1981), but Regional structure ised(Tur The sgiath sandstones are interbedded with shales The regional structure is an extensional graben and coals up to 10 ft(3 m)thick. Immediately over trending northwest, away from the intersection of lying the Sgiath is a silty, sandy bioturbated shale the viking and central grabens(Figures lA and IB). that grades upwards into a series of stacked shallow Extensional subsidence of the WGG basin may have marine sands. This sequence comprises the Piper aken place during the Permian and Triassic, but Formation the major phases of graben formation occurred during These sands extend over hundreds of square miles the late jurassic and early Cretaceous. The graben on the shelf in which the piper field is located and may have developed as a reactivation of Hercynian across the WGG. They shale out on the west side features of the claymore field(Boote and gustav, 1987)

by a nonmarine sequence of siltstones, shales, lignites, tuffs, and basalt flows with occasional thin￾bedded freshwater limestones of Middle Jurassic age. In the Claymore area, and possibly the Piper area, the end of the Triassic was marked by a period of erosion. Middle Jurassic sediments in the Piper area were also partially eroded prior to deepening of the basin and deposition of the widespread, lower deltaic plain sediments of the Sgiath Formation (Maher and Harker, 1987). There was a major transgression in the late Oxfordian over the whole of the Outer Moray Firth basin area. This is represented by the "I shale" in the Piper field (Figure 5). Following this transgres￾sion, the shallow marine Piper sandstones were deposited. After the deposition of the Piper sandstones, there was major extension and extensive deepening of the Witch Ground graben (WGG). The graben had been initiated as early as Triassic times and subsidence and tilting occurred during the deposition of the Piper and Sgiath sandstones. Consequently, wells within the graben have thicker Piper and Sgiath sandstone sections than do wells on the northern margin of the WGG. The deepening of the graben and rotation of shelf areas away from the graben margin resulted in erosion of Piper and Sgiath sandstones along fault scarps and the graben margin. These sediments were probably redeposited as gravity flows within the graben. Near the end of the Jurassic, further basin extension occurred, accompanied by a widespread transgression that deposited the organic-rich shales of the Kimmeridge Clay Formation over the Outer Moray Firth basin area. The Piper structure remained high throughout the Early Cretaceous as a result of fault block rotation and a fall in sea level. This resulted in local erosion of Jurassic sediments and nondeposition of Cretaceous sediments. Only a thin, "condensed" sequence of Lower Cretaceous deposits is present in the Piper field. During the Late Cretaceous, regional subsidence and a rise in sea level resulted in the progressive onlap of the Piper structure by mark and chalks of Santonian, Campanian, and Maastrichtian age (Figure 4). By the end of the Cretaceous, tectonic movements had largely ceased and a thick sequence of Tertiary sands and clays was deposited throughout the area. The burial history of the Piper reservoir is summarized in Figure 7. Regional Structure The regional structure is an extensional graben trending northwest, away from the intersection of the Viking and Central grabens (Figures 1A and 1B). Extensional subsidence of the WGG basin may have taken place during the Permian and Triassic, but the major phases of graben formation occurred during the Late Jurassic and Early Cretaceous. The graben may have developed as a reactivation of Hercynian features. Local Structure The Piper field lies on the northern margin of the WGG. Four significant faults are present within the Piper field (Figures 3 and 8). Most of the fault movement occurred after the deposition of the Piper sandstones, but some, notably along the "D" fault, was syndepositional. The field comprises three major tilted fault blocks, dipping gently to the northeast and slightly folded along the northeast-southwest axis. The main Piper field (blocks IA and IB) dips at about 8" to the northeast (Figures 3,4, and 9). STRATIGRAPHY The oldest sediments penetrated in Piper field are Lower Carboniferous Coal Measures of the Forth Formation (Figures 2 and 10). They comprise a thinly interbedded deltaic sequence of sands, shales, and coals. Upper Permian sediments, which unconform￾ably overlie the Carboniferous, represent evaporite deposits of the Zechstein sea. Fluvio-lacustrine sedimentation followed with argillaceous Triassic red beds of the Smith Bank Formation. No Lower Jurassic rocks are present due to nondeposition or erosion. The Middle Jurassic consists of Rattray Formation volcanics and Pentland Formation alluvial to marginal-marine argillaceous clastics and coals. During the Late Jurassic transgression, the inter￾bedded sands, shales, and coals of the paralic Sgiath Formation were overlain by shallow marine sands and shales of the Piper Formation. These in turn were overlain by anoxic marine shales of the Kimmeridge Clay Formation. Synrift deposition was brought to a close during the Early Cretaceous when sandy marls and limestones of the Valhall Formation onlapped the Piper structure. Diminishing tectonic activity into the Late Cretaceous was marked by postrift hemipelagic deposition of marls, limestones, and chalks. Clastic sedimentation returned in the Tertiary, represented by a thick sequence of sands and shales. The Piper reservoir is composed of two formations within the Upper Jurassic Humber Group. These are the Oxfordian Sgiath Formation (Harker et al., 1987) and the Upper Oxfordian to Kimmeridgian Piper Formation (Deegan and Skull, 1977) (Figure 10). Originally the section now assigned to the Sgiath Formation was dated as Callovian (Maher, 1981), but this has now been revised (Turner et al., 1984). The Sgiath sandstones are interbedded with shales and coals up to 10 ft (3 m) thick. Immediately over￾lying the Sgiath is a silty, sandy, bioturbated shale that grades upwards into a series of stacked, shallow marine sands. This sequence comprises the Piper Formation. These sands extend over hundreds of square miles on the shelf in which the Piper field is located and across the WGG. They shale out on the west side of the Claymore field (Boote and Gustav, 1987)

MIDDLE JURA EARLY CRETACEOUS ERTIARY SEA LEVEL PIPER SAND Edu∽m PIPER CAPROCK DEPOSITED ALONG 'C FAULT SCARP PIPER SAND- 3.0 16 Figure 7. Typical burial history curve for Piper field. Late Cretaceous to early Tertiary oil maturation and The period of most rapid burial was during the inferred migration phase The source rock for the Piper field is the organic rich shale of the Kimmeridge Clay Formation that a directly overlies the Piper sandstone over most of the Piper field. It is widespread throughout the outer Moray firth basin and the central and viking BLOCK IA TRAP Trap Type The Piper field is a series of three major tilted BLOCK I folded fault blocks. It is the gentle folding about a A BLOCK northeast southwest axis together with the drape associated with the northeast-southwest Caledonian fault trends that provides the critical closure to the northwest and southeast( Figures 1B and 3 To the northeast, dip closure results from the gentle tilting of the shelf away from the wGG(Figures 1B, 3, and 4). To the southwest, closure is provided by a major northwest-southeast fault, the a fault(Figure 8).The BLOCK III four-way closure is mapped from seismic data and has been verified by appraisal and development 58°25胃 0 The vertical and lateral seals are shales of the Kimmeridge Clay Formation. Along the"C"fault Figure 8. Outline map of Piper field showing principal where these shales are eroded, onlapping Campanian faults and appraisal well locations marls form the seal figure 4) 92

SEA LE' EARLY I 'lDDLE I .Juk::Ic I CRETAcEous PIPER PIPER CAPR ALONG 'C' LATE CRETACEOUS OCK DEPOSITED FAULT SCARP Y TERTIARY TIME, Ma Figure 7. Typical burial history curve for Piper field. Late Cretaceous to early Tertiary oil maturation and The period of most rapid burial was during the inferred migration phase. ~'25'~ 0 - 1 Km 0 1 Mils Figure 8. Outline map of Piper field showing principal faults and appraisal well locations. The source rock for the Piper field is the organic￾rich shale of the Kimmeridge Clay Formation that directly overlies the Piper sandstone over most of the Piper field. It is widespread throughout the Outer Moray Firth basin and the Central and Viking grabens. TRAP Trap Type The Piper field is a series of three major tilted, folded fault blocks. It is the gentle folding about a northeast-southwest axis together with the drape associated with the northeast-southwest Caledonian fault trends that provides the critical closure to the northwest and southeast (Figures 1B and 3). To the northeast, dip closure results from the gentle tilting of the shelf away from the WGG (Figures lB, 3, and 4). To the southwest, closure is provided by a major northwest-southeast fault, the A fault (Figure 8). The four-way closure is mapped from seismic data and has been verified by appraisal and development drilling. The vertical and lateral seals are shales of the Kimmeridge Clay Formation. Along the "C" fault where these shales are eroded, onlapping Campanian mark form the seal (Figure 4)

下E 15/17-7 P26 P43Z 1323 214 2.0一 2.5 15/17-7 P26 P43Z -20 PIPER SAN ZECHSTEIN ZECHSTEIN Figure 9. Uninterpreted and interpreted southwest- along the southern half of line A-A' in Figures 3 and northeast seismic line through Piper field. Two-way time 4 The oil-water contact for the main part of the field Although the structural closure of the ocKS (blocks I and Il) is at 8510 ft(2594 m)subsea and occurred at the end of the jurassic, the trap for the has equalized across all of the faults. the small four. main part of the piper field was not formed until way dip closure to the southwest(block Im) has a the Campanian marls onlapped the Piper sandstones deeper oil-water contact at 9200 ft(2804 m)subsea along the"C" fault some 88 million years after the but contains only a minor amount of oil Piper sandstones had been deposited

Figure 9. Uninterpreted and interpreted southwest- along the southern half of line A-A' in Figures 3 and northeast seismic line through Piper field. Two-way time 4. in seconds. The section illustrates key seismic horizons The oil-water contact for the main part of the field Although the structural closure of the blocks (blocks I and 11) is at 8510 ft (2594 m) subsea and occurred at the end of the Jurassic, the trap for the has equalized across all of the faults. The small four- main part of the Piper field was not formed until way dip closure to the southwest (block 111) has a the Campanian mark onlapped the Piper sandstones deeper oil-water contact at 9200 ft (2804 m) subsea along the "C" fault some 88 million years after the but contains only a minor amount of oil. Piper sandstones had been deposited

The Sgiath rised of five divisi CHRONOSTRATIGRAPHY HOSTRATIGRAPHY from base to top, the m sandstone, m shale san FFERENTJATEO stone, K shale, and j sandstone(Figure 5) Throughout the field the sgiath rests unconformably on the Middle Jurassic Pentland Formation, and the I upper boundary is a conformable contact with the Piper formation Formation comprises 12 major subdi- cEN。 MANIAN ODaY visions and subsidiary shale units, commencing with I the field-wide"I shale"and ending with a reworked tIvat the top The p2 and i P14 wells(Fi 州5 s 5)do not exhibit the complete sequence because the uppermost a and B sandstones are only developed I downflank along the eastern margin of the field RYAZANIAN Figures 4 and 13A). (The a and b sandstones may deposited to the east and southeast of Piper field The above reservoir subdivision is based on log 4 KIMMERIDGIA g character correlation using primarily the GR, DlL, OxFORDIAN ww pmmmmmmux aided by the presence within n a field-wide basis is the piper formation of three radioactive horizons in the g and h sandstones, termed Glyl, Gly2, and Hy, respectively (Figures 12A, 16A, and 16B), and thin shales at the attra 35 base of the D and E sandstones( Figures 13D and 14B ). within the Sgiath, field-wide correlation of the subdivisions is relatively straightforward, but the Piper Formation exhibits a greater variability from TRIASSIC a east to west across the field as shown by the stratigraphic correlation sections(Figure 11). Wells PERMIAN in the western half of the field are relatively easy CARBONIFEROUS to correlate while those in the eastern half are more difficult, as is correlating between east and west. Sgiath lithology west of the"D"fault(Figure 8) Figure 10. Stratigraphic column relating chronostra- consists of coal, silty bioturbated shales (m shale, tigraphy to lithostratigraphy in the Witch Ground graben K shale), and planar and trough cross-bedded, rippled area. thicknesses are not to scale mediumto coarse- grained poorly to well-sorted sand stones with occasional bioturbated surfaces(J and L sandstones ). East of the"D" fault the sandstones are medium to very coarse grained, cross-bedded Reservoir moderately to poorly sorted, with numerous biotur bated surfaces overlain by coarser-grained sand The Piper field is a layered reservoir. In many stones(Maher, 1979). Body fossils are absent from ases, the layers are sandstone on sandstone and the sandstones, but the shales contain a sparse fauna show little variation in porosity. However the big including heterodont and oyster fragments. The coal differences in permeability between these layers beds, which occur in the basal M unit, are discon necessitate careful reservoir management to achieve tinuous and variable in thickness. throughout the high recovery. Those layers with the highest formation there are abundant plant and coal esistivities are where water break-through occurs fragments and minor pyrite. The sandstones are first ( Figure 5) moderately to poorly cemented with calcite Two production wells, P2 and P14 (Figure 5), define The Piper reservoir units consist of a series of the piper reservoir subdivisions used informally stacked sandstones organized in overall coarsening within the Occidental Group The P2 well is used upward cycles. Individual units may be fine to or the western and the P14 well for the eastern half medium grained medium to coarse grained and of the field The subdivisions are changed from those coarse grained to pebbly Sorting is variable, from defined by Maher(1979)following a major re. poor to excellent and occasionally bimodal. Biotur correlation exercise carried out in 1986( Figure 11). bation is pervasive except in the coarsest-grained The distribution of the various significant reservoir units and has destroyed many e primary subdivisions within the Piper Formation and the net sedimentary structures. Planar and sandstone and net oil sandstone isochores for both lamination, ripple- drift cross lamination, and pebble the Piper and the sgiath formations are shown in lined scour surfaces are the most common of the Figures 12A through 16E remaining sedimentary structures. Calcite doggers

Figure 10. Stratigraphic column relating chronostra￾tigraphy to lithostratigraphy in the Witch Ground graben area. Thicknesses are not to scale. Reservoir The Piper field is a layered reservoir. In many cases, the layers are sandstone on sandstone and show little variation in porosity. However, the big differences in permeability between these layers necessitate careful reservoir management to achieve high recovery. Those layers with the highest resistivities are where water break-through occurs first (Figure 5). Two production wells, P2 and P14 (Figure 5), define the Piper reservoir subdivisions used informally within the Occidental Group. The P2 well is used for the western and the P14 well for the eastern half of the field. The subdivisions are changed from those defined by Maher (1979) following a major re￾correlation exercise carried out in 1986 (Figure 11). The distribution of the various significant reservoir subdivisions within the Piper Formation and the net sandstone and net oil sandstone isochores for both the Piper and the Sgiath formations are shown in Figures 12A through 16E. The Sgiath is comprised of five divisions as follows: from base to top, the M sandstone, M shale, L sandstone, K shale, and J sandstone (Figure 5). Throughout the field the Sgiath rests unconformably on the Middle Jurassic Pentland Formation, and the upper boundary is a conformable contact with the Piper Formation. The Piper Formation comprises 12 major subdi￾visions and subsidiary shale units, commencing with the field-wide "I shale" and ending with a reworked zone (Unit IV) at the top. The P2 and P14 wells (Figure 5) do not exhibit the complete sequence because the uppermost A and B sandstones are only developed downflank along the eastern margin of the field (Figures 4 and 13A). (The A and B sandstones may be equivalent to the Galley sandstones [Figure 101 deposited to the east and southeast of Piper field.) The above reservoir subdivision is based on log character correlation using primarily the GR, DLL, FDC, and CNL. Correlation on a field-wide basis is aided by the presence within the Piper Formation of three radioactive horizons in the G and H sandstones, termed Glyl, Gly2, and Hy, respectively (Figures 12A, 16A, and 16B), and thin shales at the base of the D and E sandstones (Figures 13D and 14B). Within the Sgiath, field-wide correlation of the subdivisions is relatively straightforward, but the Piper Formation exhibits a greater variability from east to west across the field as shown by the stratigraphic correlation sections (Figure 11). Wells in the western half of the field are relatively easy to correlate while those in the eastern half are more difficult, as is correlating between east and west. Sgiath lithology west of the "D" fault (Figure 8) consists of coal, silty bioturbated shales (M shale, K shale), and planar and trough cross-bedded, rippled, medium- to coarse-grained, poorly to well-sorted sand￾stones with occasional bioturbated surfaces (J and L sandstones). East of the "D" fault the sandstones are medium to very coarse grained, cross-bedded, moderately to poorly sorted, with numerous biotur￾bated surfaces overlain by coarser-grained sand￾stones (Maher, 1979). Body fossils are absent from the sandstones, but the shales contain a sparse fauna including heterodonts and oyster fragments. The coal beds, which occur in the basal M unit, are discon￾tinuous and variable in thickness. Throughout the formation there are abundant plant and coal fragments and minor pyrite. The sandstones are moderately to poorly cemented with calcite. The Piper reservoir units consist of a series of stacked sandstones organized in overall coarsening￾upward cycles. Individual units may be fine to medium grained, medium to coarse grained, and coarse grained to pebbly. Sorting is variable, from poor to excellent and occasionally bimodal. Biotur￾bation is pervasive except in the coarsest-grained units and has destroyed many of the primary sedimentary structures. Planar and trough cross￾lamination, ripple-drift cross-lamination, and pebble￾lined scour surfaces are the most common of the remaining sedimentary structures. Calcite doggers