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 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 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 Maureen Field, Block 16/29a, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 347-352 ◽  
Author(s):  
P. L. Cutts
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Upper Jurassic ◽  
Reservoir Properties ◽  
Injection Wells ◽  
The North ◽  
Clay Shales ◽  
Gravity Flows ◽  
Production Wells ◽  
The Uk

AbstractThe Maureen 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 late 1972 by the 16/29-1 well, and was confirmed by three further appraisal wells. The reservoir consists of submarine fan sandstones of the Palaeocene Maureen Formation, deposited by sediment gravity flows sourced from the East Shetland Platform. The Palaeocene sandstones, ranging from 140 to 400 ft in thickness, have good reservoir properties, with porosities ranging from 18-25% and permeabilities ranging from 30-3000 md. Hydrocarbons are trapped in a simple domal anticline, elongated NW-SE, which was formed at the Palaeocene level by Eocene/Oligocene-aged movement of underlying Permian salt. The reservoir sequence is sealed by Lista Formation claystones. Geochemical analysis suggests Upper Jurassic Kimmeridge Clay shales have been the source of Maureen hydrocarbons. Estimated recoverable reserves are 210 MMBBL. Twelve production wells have been drilled on the Maureen Field. A further seven water injection wells have been drilled to maintain reservoir pressure.

The V-Fields, Blocks 49/16, 49/21/, 48/20a, 48/25b, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 861-870
Author(s):  
James Courtier ◽  
Hugh Riches
Keyword(s):  
North Sea ◽  
Early Permian ◽  
The North ◽  
Recoverable Reserves ◽  
Production Wells ◽  
Exploration Drilling ◽  
Structural Relief ◽  
The Uk ◽  
Gas Fields ◽  
North And South

AbstractThe Vulcan, Vanguard, North and South Valiant gas fields are collectively known as the V-Fields and lie on the eastern flank of the Sole Pit Basin in the southern sector of the UK North Sea. They are contained within blocks 49/16, 49/21, 48/20a and 48/25b and are operated by Conoco (UK) Ltd. The first field to be discovered was South Valiant, in 1970, and the initial phase of exploration drilling continued until 1983, with the discovery of the North Valiant, Vanguard and Vulcan fields. Prominent faults and dip closures define the limits of the fields and gas is contained within aeolian sands of Early Permian age. The gross average reservoir thickness is approximately 900 ft with porosities ranging from 3-23% and permeabilities varying from 0.1 mD to 2 Darcies in producing zones. The development of the V-Fields consisted of drilling centrally located production wells in each field, targeting higher quality reservoir zones in areas of maximum structural relief. Initial gas-in-place is estimated at 2.6 TCF with recoverable reserves of about 1.6 TCF. The fields were brought on-stream in October 1988 and currently produce, as of November 1999, up to 260MMSCFD of gas through the LOGGS complex to the Conoco terminal at Theedle-thorpe, Lincolnshire.

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.

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 Cyrus Field, Block 16/28, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 295-300 ◽  
Author(s):  
D. G. Mound ◽  
I. D. Robertson ◽  
R. J. Wallis
Keyword(s):  
North Sea ◽  
Field Development ◽  
Fine Grained ◽  
The North ◽  
Offshore Production ◽  
Fault Block ◽  
Single Well ◽  
The North Sea ◽  
Net To Gross ◽  
The Uk

AbstractThe Cyrus Oilfield is located in Block 16/28 of the UK sector of the North Sea approximately 250 km (155 miles) NE of Aberdeen and 55 km (34 miles) NE of the Forties Field. The trap consists of a broad, very low relief four-way dip closure developed over a deeper tilted fault block. The reservoir consists of submarine-fan sandstones of late Palaeocene age, belonging to the Andrew Formation. Provenance was to the NW resulting from the early Tertiary sea-level fall which exposed the East Shetland Platform. The reservoir has been sub-divided into two zones, an upper zone of interbedded sandstones and mudstones with net to gross ratios of 0.4 to 0.6 and sandstone porositites of 12% to 18%, and a lower zone of massive fine-grained sandstones plus subordinate thin shales and limestones, with net to gross ratios in excess of 0.9 and porosities averaging 20%. The reservoir is filled with undersaturated oil of 35° API and is normally pressured. The estimate of initial oil-in-place is 75 MMBBL. Development of the field is centred on the use of BP's SWOPS (Single Well Offshore Production System) vessel using two horizontal field development wells which feed into a single seabed template for offtake. Ultimate recovery from the field is estimated to be approximately 12 MMBBL.

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