Abstract The Scott Field straddles Blocks 15/21 and 15/22 on the southern flanks of the Witch Ground Graben in the Outer Moray Firth Basin, UKCS. The oil field is developed in the highly productive Upper Jurassic Humber Group sandstones of Oxfordian to Kimmeridgian age. The field was discovered in 1983, sanctioned in 1990, and produced first oil in 1993. The field structure, effectively a large southwards tilted fault block, is compartmentalized into a series of four main pressure isolated fault blocks by mid to late Jurassic faulting. The Kimmeridge Clay Formation provides both the top seal and the source of the trapped hydrocarbons. Fluid contact, overpressure and compositional trends suggest that the trap was filled primarily from the north. Some trap-defining faults were already active during the deposition of the reservoir intervals. Well data indicate that the development of accommodation space was technically controlled during this period, with subsidence occurring more rapidly in the western areas of the field. The Scott Field reservoir consists of two major sand packages, the Scott Sandstone Member and the Piper Sandstone Member, bounded above and below by marine flooding surfaces. The late Oxfordian Scott Sandstone Member consists of a westwards prograding marine shoreface sandstone overlain by aggradational and retrogradational back-barrier deposits. Above this, the Mid Shale is a regionally extensive flooding event separating the Scott Sandstone Member from the overlying Piper Sandstone Member. The early Kimmeridgian Piper Sandstone Member consists of stacked mass flow sandstones, overlain by a shoreface/back-barrier system. Lateral facies changes and thickness variations significantly affect reservoir distribution in both Scott and Piper intervals. The best reservoir quality occurs within the coarsest grained, highest energy facies, particularly the shoreface and proximal washover deposits. At the crest of the field, 10400 ft TVDss, multi-Darcy permeabilities and porosities of 20% are common. However, reservoir quality declines progressively downflank due to increased quartz cementation and compaction. The Scott Field currently produces from 23 wells supported by 20 water injectors. Current modelling is aimed at targeting bypassed oil to increase ultimate recovery. The field has presently produced 300 MMSTB of oil from forecast reserves of 440 MMSTB with an estimated ultimate recovery factor of c. 46%.

Abstract Piper oil field lies in UK block 15/17, near the eastern end of the Moray Firth basin, 125 mi (200 km) northeast of Aberdeen, Scotland. The field was discovered in January, 1973 and confirmed as a major oil field in 1973 with five appraisal wells and one exploratory well. A steel platform with 36 well slots and space for two drilling rigs 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. Production is from the Upper Jurassic Piper Sandstone, a high energy, marginal marine and shallow marine, shelf sandstone with gross thickness ranging from 160 to 465 ft (50 to 142 m); net sand ranges from 131 to 378 ft (40 to 115 m); average porosity is 24%; permeabilities range from 200 to 1,200 md in lower energy bioturbated sandstones, and range from 2,000 to 10,000 md in higher energy sandstones. Kimmeridge Shale is the caprock over most of the field, but Upper Cretaceous marlstones provide the seal along some fault scarps where the Kimmeridge was removed during the Cenomanian. The field is comprised of three folded, tilted blocks on the northern edge of the Witch Ground graben. Block I, a gently folded fault block dipping 5° northeast, has a common oil-water contact of 8,512 ft (2,594 m) subsea with Block II. Block II, a downthrown, northwest to southeast trending fault block lies southwest of Block I. Blocks I and II cover 7,149 productive acres (2,894 ha.) and have a gross reservoir column of 1,312 ft (399 m), from 7,200 ft (2,195 m) subsea to the oil-water contact. Block III (to the southwest) borders the Witch Ground graben and contains a small accumulation with a separate oil-water contact at 9,199 ft (2,804 m) subsea. The P1 production well spudded October 10,1976, established commercial production December 7,1976, at more than 30,000 b/d, restricted by 5 1/2 in. (14 cm) tubing. The P7 well completed in April 1977 produced more than 50,000 b/d, restricted by 7 in. (17.8 cm) tubing. Twenty-five wells have been drilled, four as water injectors to support a natural water drive of 250,000 b/d. Production is 280,000± b/d of 37° API, low sulfur oil and original recoverable reserves are estimated to be 618 million bbl. Piper sand stratigraphy, reservoir performance, and development from a centrally located platform are discussed in detail.

Abstract The Renee Field lies in Block 15/27 toward the eastern end of the Renee Ridge, a major intra-basinal high in the Outer Moray Firth separating the Witch Ground Graben and South Halibut Graben. The block was awarded to a Phillips Petroleum-led consortium in the fourth Round of UKCS Licensing in March 1972. The 15/27-1 discovery well was drilled in 1976, testing oil at rates of 8025 bopd from stacked Piper/Upper Scott sandstone reservoirs. The field was appraised in mid-1997 and an Annex B submitted to the Department of Trade and Industry in late 1997 for a joint Renee and Rubie Field development. Oil export was via a 21 km pipeline to the Ivanhoe/Rob Roy fields, north of Renee. The development comprised a three-well drilling programme, completed in August 1999. First production was achieved in February 1999 at rates of up to 20 000 bopd, the plateau period continuing until year end. Production continued to decline until the field was permanently shut-in during September 2006. Ultimate recovery was 8.9 MMbbl and recovery factor 49%, based on a final mapped stock tank oil-in-place of 18.2 MMbbl. Decommissioning of the Renee Field commenced in 2015 with the removal of the subsea infrastructure.

Upper Jurassic sandstones deposited in a shallow-marine deltaic setting in the Piper Field of the Outer Moray Firth area, North Sea, show high-frequency fluctuations in apatite:tourmaline ratios that appear to be related to sea-level change. Because apatite and tourmaline are both stable during burial diagenesis and have similar hydraulic behavior, variations in the apatite:tourmaline ratio indicate either differences in sediment provenance or in the extent of floodplain weathering, apatite being unstable during weathering. Other provenance-sensitive heavy mineral ratios (rutile:zircon, monazite:zircon, chrome spinel:zircon) and mineral-chemical data from detrital garnet assemblages show that sandstones with high apatite:tourmaline have the same provenance as sandstones with low apatite:tourmaline. Fluctuations in apatite:tourmaline ratios are therefore attributed to the extent of weathering during floodplain residence prior to the sediment entering the marine system. Sedimentological data indicate that sandstones with high apatite:tourmaline were deposited during sea-level highstands, whereas sandstones with low apatite:tourmaline were deposited during lowstands. The implication of this observation is that during sea-level lowstands, sediment undergoes more prolonged floodplain residence than during highstands, apparently the direct result of the increase in areal extent of the floodplain. The fluctuations in apatite:tourmaline offer an opportunity for high-resolution correlation in the Piper Field. If similar patterns become apparent in other areas, variations in apatite:tourmaline ratios could also provide a basis for identifying highstand and lowstand events, and help establish whether deep-water submarine fan sandstones were deposited during highstands or lowstands.

Abstract The Donan Field is a mature asset in the final phase of production, following the redevelopment facilitated by various advances in technology and subsurface understanding. The original development utilized an ingenious single-well oil production system vessel which made small hydrocarbon accumulations economic, while the use of a floating production, storage and offloading vessel to redevelop the Donan Field as the ‘Dumbarton Project’ allowed the previously stranded Lochranza and undiscovered Balloch fields to be developed. Donan and Lochranza are typical Paleocene oilfields with excellent water drive from a large regional aquifer. Balloch is an Upper Jurassic oilfield of equivalent size to Lochranza supported by a large regional aquifer but has a considerably higher recovery factor on account of excellent reservoir properties combined with a more optimal geometry to effectively sweep the reservoir. Most of the fields have exceeded pre-development expectations, particularly Balloch on account of it being developed whilst considerable subsurface uncertainties remained. Recognition of a seismic amplitude v. offset response across the Donan Field was key to redevelopment, significantly increasing the oil in place and guiding the locations of development wells. This was supplemented by the ability to geosteer the horizontal development wells in the shallowest possible reservoir sand to maximize the recoverable resources. The use of horizontal development wells facilitated the development of short, areally extensive, oil columns; while the design of the production facilities and wells to include permanent artificial lift and capacity to process large water volumes was essential.