The Scott Field, Blocks 15/21a, 15/22, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 467-482 ◽  
Author(s):  
Simon Guscott ◽  
Ken Russell ◽  
Andrew Thickpenny ◽  
Robert Poddubiuk
Keyword(s):  
Upper Jurassic ◽  
Oil Field ◽  
Reservoir Quality ◽  
Accommodation Space ◽  
The North ◽  
Moray Firth ◽  
The Witch ◽  
Thickness Variations ◽  
Well Data ◽  
Clay Formation

AbstractThe 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%.

The Buzzard Field, Blocks 19/5a, 19/10a, 20/1 and 20/6a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 691-704 ◽  
Author(s):  
E. E. Taylor ◽  
N. J. Webb ◽  
C. J. Stevenson ◽  
J. R. Henderson ◽  
A. Kovac ◽  
...  
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Depositional Model ◽  
Performance Expectations ◽  
North West ◽  
Field Development ◽  
The North ◽  
Moray Firth ◽  
The North Sea ◽  
Clay Formation

AbstractThe Buzzard Field remains the largest UK Continental Shelf oil discovery in the last 25 years. The field is located in the Outer Moray Firth of the North Sea and comprises stacked Upper Jurassic turbidite reservoirs of Late Kimmeridgian–Mid Volgian age, encased within Kimmeridge Clay Formation mudstones. The stratigraphic trap is produced by pinchout of the reservoir layers to the north, west and south. Production commenced in January 2007 and the field has subsequently produced 52% over the estimated reserves at commencement of development, surpassing initial performance expectations. Phase I drilling was completed in 2014 with 38 wells drilled from 36 platform slots. Platform drilling recommenced in 2018, followed in 2019 by Phase II drilling from a new northern manifold location.The evolution of the depositional model has been a key aspect of field development. Integration of production surveillance and dynamic data identified shortcomings in the appraisal depositional model. A sedimentological study based on core reinterpretation created an updated depositional model, which was then integrated with seismic and production data. The new depositional model is better able to explain non-uniform water sweep in the field resulting from a more complex sandbody architecture of stacked channels prograding over underlying lobes.

The Highlander Field, Block 14/20b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 323-329 ◽  
Author(s):  
M. WHITEHEAD ◽  
S. J. PINNOCK
Keyword(s):  
Lower Cretaceous ◽  
Upper Jurassic ◽  
Oil Accumulation ◽  
Shallow Marine ◽  
Oil Development ◽  
The North ◽  
Recoverable Reserves ◽  
Fault Block ◽  
The Witch ◽  
Clay Formation

AbstractHighlander Field, discovered in 1976, is a small oil accumulation located 7½ miles northwest of the Tartan Platform and 114 miles northeast of Aberdeen in UK Block 14/20b. The Field lies on the NW-SE-trending Claymore-Highlander Ridge which forms the southern margin of the Witch Ground Graben. Upper Jurassic sandstones of the shallow marine Piper Formation and deeper marine turbidites (the 'Hot Lens Equivalent') within the Kimmeridge Clay Formation form the principal reservoirs. An additional important reservoir occurs within Lower Cretaceous turbidite sandstone and a small crestal accumulation occurs in Carboniferous deltaic sandstone. The structure is a tilted NW-SE-trending fault block downthrown to the northeast. The sandstone reservoirs all dip to the south and southwest and become thin due to onlap or truncation to the north. The Field has a combined structural-stratigraphic trap configuration. Seal is provided by Upper Jurassic siltstone and Lower Cretaceous calcareous clay stone. The accumulations have been sourced from the Kimmeridge Clay Formation in adjacent basins. Eight wells delineate the structure and production is currently 30 000 BOPD. Ultimate recoverable reserves are 70 million barrels of crude oil. Development has been achieved utilizing an innovative remote subsea system, connected to the Tartan Platform 7½ miles to the southeast.

The Petronella Field, Block 14/20b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 353-360 ◽  
Author(s):  
P. Waddams ◽  
N. M. Clark
Keyword(s):  
Oil And Gas ◽  
Upper Jurassic ◽  
Fault System ◽  
The North ◽  
Recoverable Reserves ◽  
Major Fault ◽  
Current Production ◽  
Main Portion ◽  
The Witch ◽  
Clay Formation

AbstractPetronella Field is a small oil and gas accumulation located 110 miles northeast of Aberdeen in UK Block 14/20b. The field lies on the highest part of the east-west-trending Petronella Ridge approximately 6 miles southwest of the Witch Ground Graben axis. The reservoir is Upper Jurassic in age and lies some 7500 ft below sea level. It comprises shallow marine sandstone of the Piper Formation ('Principal Reservoir Sequence') overlain by deeper marine turbidites ('Hot Lens Equivalent') of the Kimmeridge Clay Formation. The structure is a tilted fault block which is bounded to the north by a major fault system, downthrown to the north. Sandstone units dip to the south and thin or are truncated to the north as a result of erosion of the crest of the structure. Seal is effected by Upper Jurassic siltstone and Lower Cretaceous calcareous claystone. The accumulation has been sourced from maturation of the Kimmeridge Clay Formation below approximately 10000 ft in adjacent basins. The Field was discovered in February 1975 and is delineated by six wells. Current production of 13 000 BOPD comes from one well and uses an innovative remote subsea system controlled from, and with pipelines to, the Tartan Platform 6.4 miles to the east. Ultimate recoverable reserves from the main portion of the Field are 17 MMBBL of crude oil.

scholarly journals Geological evolution of the Chalk Group in the northern Dutch North Sea: inversion, sedimentation and redeposition

2018 ◽  
Vol 156 (07) ◽  
pp. 1265-1284
Author(s):  
EVA VAN DER VOET ◽  
LEONORA HEIJNEN ◽  
JOHN J. G. REIJMER
Keyword(s):  
North Sea ◽  
Late Cretaceous ◽  
Seismic Survey ◽  
Structural Elements ◽  
The North ◽  
Show Evidence ◽  
New Finding ◽  
The North Sea ◽  
Thickness Variations ◽  
Well Data

AbstractIn contrast to the Norwegian and Danish sectors, where significant hydrocarbon reserves were found in chalk reservoirs, limited studies exist analysing the chalk evolution in the Dutch part of the North Sea. To provide a better understanding of this evolution, a tectono-sedimentary study of the Late Cretaceous to Early Palaeogene Chalk Group in the northern Dutch North Sea was performed, facilitated by a relatively new 3D seismic survey. Integrating seismic and biostratigraphic well data, seven chronostratigraphic units were mapped, allowing a reconstruction of intra-chalk geological events.The southwestward thickening of the Turonian sequence is interpreted to result from tilting, and the absence of Coniacian and Santonian sediments in the western part of the study area is probably the result of non-deposition. Seismic truncations show evidence of a widespread inversion phase, the timing of which differs between the structural elements. It started at the end of the Campanian followed by a second pulse during the Maastrichtian, a new finding not reported before. After subsidence during the Maastrichtian and Danian, renewed inversion and erosion occurred at the end of the Danian. Halokinesis processes resulted in thickness variations of chalk units of different ages.In summary, variations in sedimentation patterns in the northern Dutch North Sea relate to the Sub-Hercynian inversion phase during the Campanian and Maastrichtian, the Laramide inversion phase at the end of the Danian, and halokinesis processes. Additionally, the Late Cretaceous sea floor was characterized by erosion through contour bottom currents at different scales and resedimentation by slope failures.

GEOLOGY OF BARROW ISLAND OIL FIELD

1973 ◽  
Vol 13 (1) ◽  
pp. 49 ◽  
Author(s):  
Keith Crank
Keyword(s):  
Oil And Gas ◽  
Water Injection ◽  
Water Source ◽  
Upper Jurassic ◽  
Oil Field ◽  
Late Triassic ◽  
Low Permeability ◽  
High Porosity ◽  
The South ◽  
The North

The Barrow Island oil field, which was discovered by the drilling of Barrow 1 in 1964, was declared commercial in 1966. Since then 520 wells have been drilled in the development of this field which has resulted in 309 Windalia Sand oil producers (from about 2200 feet), eight Muderong Greensand oil wells (2800 feet), five Neocomian/Upper Jurassic gas and oil producers (6200 to 6700 feet), eight Barrow Group water source wells and 157 water injection wells.Production averages 41,200 barrels of oil per day, and 98% of this comes from the shallow Windalia Sand Member of Cretaceous (Aptian to Albian) age. These reserves are contained in a broad north-plunging nose truncated to the south by a major down-to-the-south fault. The anticline is thought to have been formed initially from a basement uplift during Late Triassic to Early Jurassic time. Subsequent periods of deposition, uplift and erosion have continued into the Tertiary and modified the structure to its present form. The known sedimentary section on Barrow Island ranges from Late Jurassic to Miocene.The Neocomian/Jurassic accumulations are small and irregular and are not thought to be commercial in themselves. The Muderong Greensand pool is also a limited, low permeability reservoir. Migration of hydrocarbons is thought to have occurred mainly in the Tertiary as major arching did not take place until very late in the Cretaceous or early in the Palaeocene.The Windalia Sand reservoir is a high porosity, low permeability sand which is found only on Barrow Island. One of the most unusual features of this reservoir is the presence of a perched gas cap. Apparently the entire sand was originally saturated with oil, and gas subsequently moved upstructure from the north, displacing it. This movement was probably obstructed by randomly-located permeability barriers.

scholarly journals Petroleum potential of the Upper Jurassic Hareelv Formation, Jameson Land, East Greenland

2018 ◽  
pp. 85-113 ◽  
Author(s):  
Jørgen A. Bojesen-Koefoed ◽  
Morten Bjerager ◽  
H. Peter Nytoft ◽  
Henrik I. Petersen ◽  
Stefan Piasecki ◽  
...  
Keyword(s):  
Significant Proportion ◽  
Upper Jurassic ◽  
Geochemical Data ◽  
Eastern Canada ◽  
Petroleum Potential ◽  
East Greenland ◽  
North East ◽  
The North ◽  
Clay Formation

The marine, mudstone-dominated Hareelv Formation (Upper Jurassic) of Jameson Land, East Greenland is a representative of the widespread Kimmeridge Clay Formation equivalents, sensu lato, known from the greater North Atlantic region, western Siberia and basins off eastern Canada. These deposits constitute the most important petroleum source-rock succession of the region. The present study reports petroleum geochemical data from the 233.8 m thick succession penetrated by the fully cored Blokelv-1 borehole, and includes supplementary data from outcrop samples and other boreholes in Jameson Land. The succession consists of basinal mudstone intercalated with a significant proportion of gravity-flow sandstones, both in situ and remobilised as injectites. The mudstones are generally rich in organic carbon with values of TOC reaching nearly 19 wt% and high pyrolysis yields reaching values of S2 up to nearly 43 kg HC/ton. Hydrogen Indices are up to 363. The data presented herein demonstrate that weathering of abundant pyritic sulfur adversely affects the petroleum potential of the kerogen in outcrop samples. The succession is thermally immature to early mature, except where intrusions have locally heated adjacent mudstones. The documentation of rich gas/oil-prone Upper Jurassic successions in Jameson Land is important for the assessment of the regional petroleum potential, including the North-East Greenland continental shelf.

scholarly journals The Evaluation of Reservoir Quality of Mishrif Formation in South and North Domes of Buzurgan Oil Field

2019 ◽  
Vol 9 (4) ◽  
pp. 89-106
Author(s):  
Ali Duair Jaafar ◽  
Dr. Medhat E. Nasser
Keyword(s):  
Physical Properties ◽  
Water Saturation ◽  
Oil Field ◽  
Reservoir Quality ◽  
Petrophysical Properties ◽  
The South ◽  
Reservoir Properties ◽  
Formation Evaluation ◽  
The North

Buzurgan field in the most cases regards important Iraqi oilfield, and Mishrif Formation is the main producing reservoir in this field, the necessary of so modern geophysical studies is necessity for description and interpret the petrophysical properties in this field. Formation evaluation has been carried out for Mishrif Formation of the Buzurgan oilfield depending on logs data. The available logs data were digitized by using Neuralog software. A computer processed interpretation (CPI) was done for each one of the studied wells from south and north domes using Techlog software V2015.3 in which the porosity, water saturation, and shale content were calculated. And they show that MB21 reservoir unit has the highest thickness, which ranges between (69) m in north dome to (83) m in south dome, and the highest porosity, between (0.06 - 0.16) in the north dome to (0.05 -0.21) in the south dome. The water saturation of this unit ranges between (25% -60%) in MB21 of north dome. It also appeared that the water saturation in the unit MB21 of south dome has the low value, which is between (16% - 25%). From correlation, the thickness of reservoir unit MB21 increases towards the south dome, while the thickness of the uppermost barrier of Mishrif Formation increases towards the north dome. The reservoir unit MB21 was divided into 9 layers due to its large thickness and its important petrophysical characterization. The distribution of petro physical properties (porosity and water saturation) has shown that MB 21 has good reservoir properties.

BURIAL HISTORY OF THE EASTERN OFFICER BASIN, SOUTH AUSTRALIA

1995 ◽  
Vol 35 (1) ◽  
pp. 307 ◽  
Author(s):  
R. Moussavi-Harami ◽  
D. I. Gravestock
Keyword(s):  
South Australia ◽  
Bounded Sequence ◽  
Source Rocks ◽  
Sediment Loading ◽  
Burial History ◽  
Fine Grained ◽  
Accommodation Space ◽  
The North ◽  
History Of ◽  
Well Data

The intracratonic Officer Basin of central Australia was formed during the Neoproterozoic, approximately 820 m.y. ago. The eastern third of the Officer Basin is in South Australia and contains nine unconformity-bounded sequence sets (super-sequences), from Neoproterozoic to Tertiary in age. Burial history is interpreted from a series of diagrams generated from well data in structurally diverse settings. These enable comparison between the stable shelf and co-existing deep troughs. During the Neoproterozoic, subsidence in the north (Munyarai Trough) was much higher than in either the south (Giles area) or northeast (Manya Trough). This subsidence was related to tectonic as well as sediment loading. During the Cambrian, subsidence was much higher in the northeast and was probably due to tectonic and sediment loading (carbonates over siliciclastics). During the Early Ordovician, subsidence in the north created more accommodation space for the last marine transgression from the northeast. The high subsidence rate of Late Devonian rocks in the Munyarai Trough was probably related to rapid deposition of fine-grained siliciclastic sediments prior to the Alice Springs Orogeny. Rates of subsidence were very low during the Early Permian and Late Jurassic to Early Cretaceous, probably due to sediment loading rather than tectonic sinking. Potential Neoproterozoic source rocks were buried enough to reach initial maturity at the time of the terminal Proterozoic Petermann Ranges Orogeny. Early Cambrian potential source rocks in the Manya Trough were initially mature prior to the Delamerian Orogeny (Middle Cambrian) and fully mature on the Murnaroo Platform at the culmination of the Alice Springs Orogeny (Devonian).

The Claymore Field, Block 14/19, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 269-278 ◽  
Author(s):  
S. D. Harker ◽  
S. C. H. Green ◽  
R. S. Romani
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Central Area ◽  
Upper Jurassic ◽  
Daily Production ◽  
Northern Area ◽  
Main Area ◽  
Cumulative Production ◽  
The Witch ◽  
Clay Formation

AbstractThe Claymore Field is located in UK North Sea Block 14/19 on the southwest margin of the Witch Ground Graben. The principal structure is a southerly tilted and truncated fault block. The field is divided into three producing areas. Major production is from Upper Jurassic paralic sandstones of the Sgiath Formation and turbidite sandstones of the Claymore Sandstone Member of the Kimmeridge Clay Formation in the downflank Main Area. Minor production is from Permian carbonates of the Halibut Bank Formation and Carboniferous sandstones of the Forth Formation in the crestal Central Area. The Northern Area is a northerly plunging nose, extending graben wards from the Claymore tilt block. Production in the Northern Area is from Lower Cretaceous turbidite sandstones of the Valhall Formation.A small amount of oil was recovered on a wireline test in 1972 from Permian carbonates in the crestally located 14/19-1 well, in what is now termed the Central Area. In 1974 the Main Area was discovered by the southerly downdip well 14/19-2, and the Northern Area was discovered by the northerly downdip well 14/19-6A. Initial oil in place was 1452.9 MMBBL with currently estimated ultimate proved recovery of 511.0 MMBBL of oil. A 36-slot steel platform was installed in 1977. Two subsea water-injection templates were added in 1981 and 1985. Cumulative production to 6 July 1988 was 322.9 MMBBL of oil and daily production was 75 000 BOPD of oil from 28 producers, supported by 16 injectors.

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