Facies-related diagenesis in the Main Claymore Oilfield sandstones

Clay Minerals ◽  
1986 ◽  
Vol 21 (4) ◽  
pp. 479-496 ◽  
Author(s):  
I. S. C. Spark ◽  
N. H. Trewin
Keyword(s):  
Upper Jurassic ◽  
Burial History ◽  
Pore Filling ◽  
Quartz Crystals ◽  
Sedimentary Sequences ◽  
The North ◽  
Major Factors ◽  
Clay Formation ◽  
Pore Lining ◽  
Ferroan Dolomite

AbstractFour major sedimentary sequences of the Triassic and Upper Jurassic of the Main Claymore Oilfield of the North Sea each contain a characteristic suite of diagenetic minerals and fabrics. (1) Triassic Skagerrak Formation fluvial sandstones contain early authigenic pore-lining smectite, together with kaolinite and chlorite which form grain replacements and pore fills. Quartz and feldspar overgrowths are minor. Ferroan dolomite forms a late diagenetic patchy poikilotopic cement. Smectite is converted to illite-smectite in a 5 m thick zone beneath the sub-Jurassic unconformity. Smectite formed early in diagenesis prior to oil migration and destroyed permeability. Thus oil is not found in these sandstones although they occur in the oilzone. (2) The Piper Formation (late Oxfordian/early Kimmeridgian) paralic deposits mainly contain authigenic, pore-lining illite-smectite, vermicular kaolinite grain replacements and pore fills. Quartz overgrowths are generally well developed. (3) The Kimmeridge Clay Formation (early Kimmeridgian/early Volgian) comprises thin marine sandstone turbidites, contained within a thick siltstone/shale sequence. In the sandstones (the ‘Ten Foot Sandstone’) discrete double-ended quartz crystals (1–20 µm) developed prior to quartz, K- and Na-feldspar overgrowths. Only minor kaolinite and lllite-smectite are present. Late diagenetic dolomitic occurs as a patchy poikilotopic cement and as clusters of pore-filling rhombs. (4) The Claymore Sandstone Member (early to middle Volgian) thick marine sandstone turbidites are interbedded with thin siltstones/shales. Sandstones have well-developed quartz, K and Na-feldspar overgrowths, and kaolinite and illite-smectite occur as grain replacements and rarely as pore fills. Late-diagenetic dolomite and ferroan dolomite form poikilotopic cement and clusters of pore-filling rhombs. The major factors which control diagenetic features are depositional environment and associated porewater together with original mineralogy. Burial history and textural features of the sandstones also have important influences. Reservoir quality is controlled by a complex interplay of these features.

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.

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 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 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.

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).

Diagenesis in Upper Jurassic marine sandstones from the North Sea Well 14/26-1 and its significance

Clay Minerals ◽  
1986 ◽  
Vol 21 (4) ◽  
pp. 513-535 ◽  
Author(s):  
C. V. Jeans ◽  
M. J. Fisher
Keyword(s):  
Organic Matter ◽  
North Sea ◽  
Upper Jurassic ◽  
Immature Stage ◽  
Maximum Temperature ◽  
Burial Depth ◽  
Hydrocarbon Generation ◽  
Clay Formation ◽  
Later Phase ◽  
Ferroan Dolomite

AbstractA tightly cemented series of marine sandstones, interbedded with shales and mudstones, occurs in the lower part of the Kimmeridge Clay Formation (Kimmeridgian to Ryazanian) of Arco Well 14/26-1 (Core No. 5, 8067–8085 ft). The well is on the northern flank of the Fraserburgh Spur Basement Ridge. The sediments are in the immature stage of hydrocarbon generation and are now at their maximum temperature and burial depth: the bottom hole temperature is 75°C. The sandstone diagenesis was complex, essentially of an intrinsic type, and took place under considerable overpressures. Initially a series of early cements was precipitated (minor chalcedony, quartz, feldspar, ferroan calcite, non-ferroan dolomite and major ferroan dolomite). A later phase of diagenesis embraced two periods of intrastratal solution (each affecting both the silicate and the carbonate components of the sediment) separated by a phase of calcite precipitation and followed by a phase of kaolinite cementation. The early cements are interpreted as being of the intrinsic miagenetic type. The later phase of diagenesis (alternating intrastratal solution and cement precipitation) resulted from the interaction of (i) the biotic breakdown of organic matter by thermophyllic micro-organisms and (ii) the abiotic thermal alteration of organic matter with the mineral components of the sediment: of particular importance were varying PCO2 and the generation of carboxylic and phenolic acids. The diagenetic pattern is closely comparable to that known from various Upper Jurassic sandy shelf sediments in other parts of the northern North Sea which have very different burial histories.

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 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.

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.

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