The Flora Field, Blocks 31/26a, 31/26c, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 549-555 ◽  
Author(s):  
R. D. Hayward ◽  
C. A. L. Martin ◽  
D. Harrison ◽  
G. Van Dort ◽  
S. Guthrie ◽  
...  
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Water Contact ◽  
Upper Carboniferous ◽  
The North ◽  
Recoverable Reserves ◽  
The North Sea ◽  
Oil Water ◽  
The Uk ◽  
Clay Formation

AbstractThe Flora Field straddles Blocks 31/26a and 31/26c of the UK sector of the North Sea on the southern margin of the Central Graben. The field is located on the Grensen Nose, a long-lived structural high, and was discovered by the Amerada Hess operated well 31/26a-12 in mid-1997.The Flora Field accumulation is reservoired within the Flora Sandstone, an Upper Carboniferous fluvial deposit, and a thin Upper Jurassic veneer, trapped within a tilted fault block. Oil is sourced principally from the Kimmeridge Clay Formation of the Central Graben and is sealed by overlying Lower Cretaceous marls and Upper Cretaceous Chalk Group.Reservoir quality is generally good with average net/gross of 85% and porosity of 21%, although permeability (Kh) exhibits a great deal of heterogeneity with a range of 0.1 to <10000mD (average 300 mD). The reservoir suffers both sub-horizontal (floodplain shales) and vertical (faults) compartmentalization, as well as fracturing and a tar mat at the oil-water contact modifying flow and sweep of the reservoir. Expected recoverable reserves currently stand at 13 MMBBL

The Maria Field, Block 16/29a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 875-885 ◽  
Author(s):  
I. N. Stephens ◽  
S. Small ◽  
P. H. Wood
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
The North ◽  
Recoverable Reserves ◽  
Fault Block ◽  
Production Wells ◽  
The North Sea ◽  
The Uk ◽  
Clay Formation

AbstractThe Maria oilfield is located on a fault-bounded terrace in Block 16/29a of the UK sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in December 1993 by the 16/29a-11Y well and was confirmed by two further appraisal wells. The reservoir consists of shoreface sandstones of the Jurassic Fulmar Formation. The Jurassic sandstones, ranging from 100 to 180 ft in thickness, have variable reservoir properties, with porosities ranging from 10 to 18% and permeabilities from 1 to 300 mD. Hydrocarbons are trapped in a truncated rotated fault block, striking NW–SE. The reservoir sequence is sealed by Kimmeridge Clay Formation and Heather Formation claystones. Geochemical analysis suggests that Middle Jurassic Pentland Formation and Upper Jurassic Kimmeridge Clay Formation mudstones have been the source of the Maria hydrocarbons. Estimated recoverable reserves are 10.6 MMbbl and 67 bcf (21.8 MMboe). Two further production wells were drilled in 2018 to access unexploited areas.

The MacCulloch Field, Block 15/24b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 453-466 ◽  
Author(s):  
C. Gunn ◽  
J. A. MacLeod ◽  
P. Salvador ◽  
J. Tomkinson
Keyword(s):  
North Sea ◽  
Water Contact ◽  
Northern Flank ◽  
Recoverable Reserves ◽  
Average Porosity ◽  
Oil Water ◽  
The Witch ◽  
The Uk ◽  
Clay Formation ◽  
Central North Sea

AbstractThe MacCulloch Field lies within Block 15/24b in the UK Central North Sea and is located on the northern flank of the Witch Ground Graben. It was discovered by Conoco well 15/24b-3 in 1990.MacCulloch Field is a four-way dip closure at Top Paleocene over a deeper Mesozoic structure. The reservoir consists of Upper Balmoral Sandstones containing 32-37° API oils derived from Kimmeridge Clay Formation shales and sealed by shales belonging to the Sele Formation. The field contains recoverable reserves of 60-90 MMBOE.Reservoir quality is generally very good, with an average porosity of 28% and core permeabilities (Kh) between 200 mD and 2D. AVO anomalies and a seismic flat spot are associated with oil filled reservoir and the oil-water contact in certain areas of the field.

The Magnus Field, Block 211/7a, 12a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 153-157 ◽  
Author(s):  
M. Shepherd
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Hydrocarbon Source Rock ◽  
Submarine Fan ◽  
Oil Accumulation ◽  
The North ◽  
Fault Block ◽  
The North Sea ◽  
The Uk ◽  
Clay Formation

abstractMagnus is the most northerly producing field in the UK sector of the North Sea. The oil accumulation occurs within sandstones of an Upper Jurassic submarine fan sequence. The combination trap style consists of reservoir truncation by unconformity at the crest of the easterly dipping fault block structure and a stratigraphic pinchout element at the northern and southern limits of the sand rich fan. The reservoir is enveloped by the likely hydrocarbon source rock, the organic rich mudstones of the Kimmeridge Clay Formation.

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 Tern Field, Block 210/25a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 191-198 ◽  
Author(s):  
M. Van Panhuys-Sigler Van ◽  
A. Baumann ◽  
T. C. Holland
Keyword(s):  
North Sea ◽  
Water Contact ◽  
Shetland Islands ◽  
The North ◽  
Initial Stage ◽  
Cumulative Production ◽  
Oil Water ◽  
Northern North Sea ◽  
The Uk ◽  
Complex Faulting

AbstractThe Tern Oilfield is situated 150 km northeast of the Shetland Islands in Block 210/25a in the UK sector of the northern North Sea. The discovery well 210/25-1 was drilled in 1975 in a water depth of about 541 ft. The trap is defined at around 8000 ft TVSS by a tilted horst-structure. The hydrocarbons are contained in reservoirs belonging to the Middle Jurassic Brent Group sands deposited by a wave-dominated delta system in the East Shetland Basin. Complex faulting of the structure is responsible for the division of the field into two areas with different original oil-water contacts: the Main Area of the field with an oil-water contact at 8260 ft TVSS, and the Northern Area with a possible oil-water contact at 8064 ft TVSS. Reservoir quality is good with average porosities ranging from 20-24% and an average permeability of 350 md. The expected STOIIP and ultimate recovery of oil are 452 and 175 MMBBL, respectively which represents a recovery factor of 39%.The initial stage of the development plan calls for ten wells, five oil producers and five water injectors, to be drilled from a single platform, Tern Alpha. Development drilling started in February 1989 and first oil was produced on 2 June 1989. The oil is evacuated via the North Cormorant and Cormorant Alpha platforms into the Brent System pipeline for export to the Sullom Voe terminal.To date, two producers have b een drilled and total cumulative production is 6.4 MMBBL (1 January 1990). Ultimate recovery is estimated to be some 175 MMBBL.

scholarly journals Are Carboniferous coals from the Danish North Sea oil-prone?

2007 ◽  
Vol 13 ◽  
pp. 13-16 ◽  
Author(s):  
Henrik I. Petersen ◽  
Hans P. Nytoft
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Upper Jurassic ◽  
Source Rocks ◽  
Lower Carboniferous ◽  
North West ◽  
The North ◽  
Single Well ◽  
The North Sea ◽  
Clay Formation

The Central Graben in the North Sea is a mature petroleum province with Upper Jurassic – lowermost Cretaceous marine shale of the Kimmeridge Clay Formation and equivalents as the principal source rock, and Upper Cretaceous chalk as the main reservoirs. However, increasing oil prices and developments in drilling technologies have made deeper plays depending on older source rocks increasingly attractive. In recent years exploration activities have therefore also been directed towards deeper clastic plays where Palaeozoic deposits may act as petroleum source rocks. Carboniferous coaly sections are the most obvious source rock candidates. The gas fields of the major gas province in the southern North Sea and North-West Europe are sourced from the thick Upper Carboniferous Coal Measures, which contain hundreds of coal seams (Drozdzewski 1993; Lokhorst 1998; Gautier 2003). North of the gas province Upper Carboni-ferous coal-bearing strata occur onshore in northern England and in Scotland, but offshore in the North Sea area they have been removed by erosion. However, Lower Carboniferous strata are present offshore and have been drilled in the Witch Ground Graben and in the north-eastern part of the Forth Approaches Basin (Fig. 1A), where most of the Lower Carbon iferous sediments are assigned to the sandstone/shale-dominated Tayport For mation and to the coal-bearing Firth Coal Formation (Bruce & Stemmerik 2003). Highly oil-prone Lower Carboniferous lacustrine oil shales occur onshore in the Midland Valley, Scotland, but they have only been drilled by a single well off shore and seem not to be regionally distributed (Parnell 1988). In the southern part of the Norwegian and UK Central Graben and in the Danish Central Graben a total of only nine wells have encountered Lower Carboniferous strata, and while they may have a widespread occurrence (Fig. 1B; Bruce & Stemmerik 2003) their distribution is poorly constrained in this area. The nearly 6000 m deep Svane-1/1A well (Fig. 1B) in the Tail End Graben encountered gas and condensate at depths of 5400–5900 m, which based on carbon isotope values may have a Carboniferous source (Ohm et al. 2006). In the light of this the source rock potential of the Lower Carboniferous coals in the Gert-2 well (Fig. 1C) has recently been assessed (Petersen & Nytoft 2007).

scholarly journals The Innes Field, Block 30/24, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 488-497 ◽  
Author(s):  
J. G. Gluyas ◽  
P. Arkley
Keyword(s):  
North Sea ◽  
Oil And Gas ◽  
Upper Jurassic ◽  
The North ◽  
Start Up ◽  
Central Trough ◽  
The North Sea ◽  
Water Cut ◽  
The Uk ◽  
Oil Company

AbstractThe abandoned Innes Field was within Block 30/24 on the western margin of the Central Trough in the UK sector of the North Sea. Hamilton Brothers Oil Company operated the licence, and Innes was the third commercially viable oil discovery in the block after Argyll and Duncan. It was discovered in 1983 with well 30/24-24. Three appraisal wells were drilled, one of which was successful. Oil occurs in the Early Permian Rotliegend Group sandstones sealed by Zechstein Group dolomites and Upper Jurassic shale.The discovery well and successful appraisal well were used for production. Export of light, gas-rich crude was via a 15 km pipeline to Argyll. Innes was produced using pressure decline. It was abandoned in 1992 having produced 5.8 MMbbl of oil and possibly 9.8 bcf of gas. Water cut was a few percent.Innes was re-examined between 2001 and 2003 by the Tuscan Energy/Acorn Oil and Gas partnership with a view to tying the field back to the newly redeveloped Argyll (Ardmore) Field but marginal economics and financial constraints for the two start-up companies prevented any further activity. Enquest currently owns the licence and the company has redeveloped Argyll/Ardmore, as Alma. There are no plans to redevelop Innes.

The North Brae Field, Block 16/7a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 43-48
Author(s):  
Mark A. Stephenson
Keyword(s):  
Upper Jurassic ◽  
Fault Scarp ◽  
Turbidity Currents ◽  
Hydrocarbon Production ◽  
The North ◽  
Recoverable Reserves ◽  
Clastic Sediments ◽  
The Uk ◽  
Clay Formation ◽  
Gas Recycling

AbstractNorth Brae is the first gas condensate field in the UK to be produced by gas recycling. The field lies at the western margin of the South Viking Graben in UK Block 16/7a. Estimated recoverable reserves are 178 MMBBL of condensate and 798 BCF of dry gas. First hydrocarbon production was in April 1988 from the Brae 'B' platform.The reservoir is composed of coarse clastic sediments of the Upper Jurassic Brae Formation which were deposited by debris flows and turbidity currents in a submarine fan setting adjacent to an active fault scarp. The Brae Formation now abuts impermeable Devonian rocks of the Fladen Ground Spur to the west. The reservoir is capped by the Kimmeridge Clay Formation, which also provided the source of the hydrocarbons.

The Fulmar Field, Blocks 30/16, 30/11b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 563-585 ◽  
Author(s):  
O. Kuhn ◽  
S. W. Smith ◽  
K. Van Noort ◽  
B. Loiseau
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Upper Jurassic ◽  
The North ◽  
Basement Faults ◽  
Wet Gas ◽  
Stratigraphic Model ◽  
Depositional Architecture ◽  
The Uk ◽  
Clay Formation

AbstractThe Fulmar Field is located on the southwestern margin of the Central Graben in Blocks 30/16 and 30/11b of the UK sector of the North Sea. The Fulmar Field was discovered 1975 and began producing in 1982. Currently (2000) the field produces at a rate of 8000 BOPD at a watercut above 90% mainly through the process of rinsing of residual oil. Total STOIIP is 822 MMBBL and ultimate recovery is 567 MMBBL of oil and 342 BSCF of wet gas. As of the end of 1999, 547 MMSTB of oil and 325 BSCF of wet gas had been produced. The high recovery factor (69%) of the field is thought to be linked to the combination of well density, large length of reservoir perforated, excellent reservoir quality, sweep by water injection, good pressure support and oil stripping from a secondary gas cap formed early in field life.The Fulmar Field is a small triangular, partly eroded domal anticline with steeply dipping flanks, located on a fault terrace within the western margin of the South West Central Graben at a depth between 9900 and 11 500 ft TVDss. The field has been shaped by three major tectonic processes: (1) halokinesis, (2) syndepositional reactivation of Caledonian basement faults; and (3) syndepositional through post-depositional displacements along the nearby Auk Horst Boundary Fault. The reservoir consists of thick Upper Jurassic, shallow marine, very bioturbated sandstones of the Fulmar Formation overlain by the deeper marine Ribble Sands interbedded within the Kimmeridge Clay Formation. Reservoir seal is provided by the Kimmeridge Clay in the west and Upper Cretaceous chalks which unconformably overlie the Fulmar Formation in the east. The reservoir section has been lithostratigraphically subdivided into six reservoir units and 24 sub-units. Integration of bio- and lithostratigraphic data has led to a sequence stratigraphic model of the Jurassic succession in the Fulmar Field. In total four depositional sequences are identified, which progressively onlap Triassic basement towards the southwest. The older Jurassic sequences are characterized by rapid progradation of shoreface sands, whereas aggradation of thick sediment packages is typical of the younger intervals. This change of depositional architecture is linked to syndepositional reactivation of basement faults. Major transgressive intervals form intra-reservoir barriers or baffles to flow. Facies changes (Mersey-Clyde Sands) from proximal to distal facies are abrupt and are also linked to basement faults.

The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 183-190 ◽  
Author(s):  
Keith J. Fletcher
Keyword(s):  
Upper Jurassic ◽  
Western Boundary ◽  
The South ◽  
Submarine Fan ◽  
Water Contact ◽  
The North ◽  
Oil Water ◽  
Clay Formation ◽  
A Minor ◽  
North And South

abstractThe Central Brae Oilfield is the smallest of three Upper Jurassic fields being developed in UK, Block 16/07a. The field was discovered in 1976 and commended production in September 1989 through a sub-sea template tied back to the Brae 'A' platform in the South Brae Oilfield. The field Stooip is 244 MMBBLs, and by May 1999 cumulative exports of oil and NGL reached 44 MMBBLs.The Central Brae reservoir is a proximal submarine fan sequence, comprising dominantly sand-matrix conglomerate and sanstone with a minor mudstone units. The sediments were shed eastwards off the Fladen Ground Spur and were deposited as a relatively small and steep fan at the margin of the South Viking Graben. Mudstone facies border the submarine fan deposits to the north and south, forming stratigraphic seals. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous, initially formed as a hangingwall anticline during extension but subsequently tightened during compressional phases. The western boundary of the field is formed by a sealing fault, whilst to the east, there is an oil-water contact at 13426 ft TVDss. The overlying seal is the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards and provides the source of the hydrocarbons.

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