The development and destruction of porosity within Upper Jurassic reservoir sandstones of the Piper and Tartan Fields, Outer Moray Firth, North Sea

Clay Minerals ◽  
1986 ◽  
Vol 21 (4) ◽  
pp. 649-694 ◽  
Author(s):  
S. D. Burley
Keyword(s):  
North Sea ◽  
Ionic Composition ◽  
Upper Jurassic ◽  
High Energy ◽  
Secondary Porosity ◽  
Water Contact ◽  
Moray Firth ◽  
Reservoir Sandstones ◽  
The Individual ◽  
Textural Evidence

AbstractUpper Jurassic Piper Formation sandstones of the Outer Moray Firth Basin, UK North Sea, form the main reservoir for the Piper and Tartan Fields, and are sealed by either the Kimmeridge Clay or Cretaceous marls. The main reservoir sandstones can be broadly considered as stacked coarsening-upward units that accumulated in a predominantly high-energy, shallow marine complex with depositional waters of inferred normal marine salinity, Eh and ionic composition. The amount of porosity and its distribution throughout these sandstones differs between the individual structural entities of the Piper and Tartan Fields. On the Piper structure all the sandstones are highly porous. Oil-zone porosities average 25% and are only slightly reduced in the water zone. Sandstones in the upthrown block of the Tartan structure are also generally porous but porosities are typically reduced to below 20%. Porosities are the most variable in the Tartan downthrown block and in the 15/17-9 well, off-structure Piper, where porous sandstones with between 14 and 18% porosity are associated with highly compacted and cemented sandstones with <5% porosity. Thin-section and SEM textural evidence indicate that much of the porosity in these sandstones is secondary, produced through the dissolution of an intergranular cement that provided support for the detrital framework, was peripherally replacive with respect to most detrital grains, and extensively replaced feldspars. Nodular concretions and sporadic, irregular crystals of ferroan calcite are inferred to be the remnants of this intergranular cement. The distribution of porosity zones in the Tartan downthrown block is related to the present structure and oil-water contact, supporting the interpretation of a secondary origin for much of the present porosity. Highly compacted sandstones interbedded with the porous sandstones result from a combination of early compaction, brittle framework collapse following the generation of secondary porosity and late grain-to-grain contact dissolution. Aggressive fluids responsible for the generation of the cement dissolution porosity are inferred to have been expelled from the Kimmeridge Clay in the adjacent Witch Ground Graben. The preservation of secondary porosity in Piper Formation sandstones is due to the relative timing of secondary porosity generation and subsequent hydrocarbon migration.

Chemostratigraphy of upper Jurassic reservoir sandstones, Danish Central Graben, North Sea

2010 ◽  
Vol 27 (7) ◽  
pp. 1572-1594 ◽  
Author(s):  
R. Weibel ◽  
P.N. Johannessen ◽  
K. Dybkjær ◽  
P. Rosenberg ◽  
C. Knudsen
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Reservoir Sandstones

The Ivanhoe and Rob Roy Fields, Blocks 15/21a-b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 331-338 ◽  
Author(s):  
R. H. Parker
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Rock Properties ◽  
Production Facility ◽  
Injection Wells ◽  
Recoverable Reserves ◽  
Fault Block ◽  
Moray Firth ◽  
Sandstone Formation ◽  
Northeast Coast

AbstractThe Ivanhoe and Rob Roy Fields are located in the Outer Moray Firth Basin, seventy nautical miles off the northeast coast of Scotland. The Ivanhoe Field was discovered in 1975, and the Rob Roy Field in 1984. The reserves in both fields occur in tilted fault block traps of Upper Jurassic, Piper Sandstone Formation. Estimated total recoverable reserves amount to 100 MMBBL and 62 BCF. The fields are separated by a water corridor approximately 1 km wide. Both fields contain two reservoir sandstone units, an upper and lower, locally termed the Supra Piper Sandstone and Main Piper Sandstone respectively. The reservoirs in both fields exhibit excellent rock' properties with porosities up to 28% and permeabilities of several Darcies.Each field is developed via a subsea manifold surrounded by a cluster of production and injection wells, of which two were pre-drilled on Ivanhoe and six pre-drilled on Rob Roy. This allowed rapid achievement of the 60 000 BOPD plateau oil production rate soon after commissioning of facilities in July 1989. The two subsea manifolds are tied into a single subsea production manifold which connects with a Floating Production Facility. Crude oil is exported to the Claymore A Platform and gas to the Tartan A Platform.

The Tolmount Field, Block 42/28d, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 262-272 ◽  
Author(s):  
A. Miles ◽  
M. Allen ◽  
L. Fairweather ◽  
J. Hilton ◽  
H. Sloan ◽  
...  
Keyword(s):  
North Sea ◽  
Burial History ◽  
Reservoir Properties ◽  
Water Contact ◽  
Diagenetic Alteration ◽  
Reservoir Sandstones ◽  
Sandstone Formation ◽  
The Uk ◽  
Continental Basin ◽  
Gas Bearing

AbstractThe Tolmount Field is a lean gas condensate accumulation located in Block 42/28d of the UK Southern North Sea. The field was discovered in 2011 by well 42/28d-12, which encountered good-quality gas-bearing reservoir sandstones of the Permian Leman Sandstone Formation. The discovery was appraised in 2013 by wells 42/28d-13 and 42/28d-13Z, which logged the gas–water contact on the eastern flank of the field. The Tolmount structure is a four-way, dip-closed, faulted anticline, orientated NW to SE. The reservoir comprises mixed aeolian dune and fluvial sheetflood facies deposited within an arid continental basin. Dune sands display the best reservoir properties with porosities around 22% and permeabilities exceeding 100 mD. Only minor diagenetic alteration has occurred, primarily in the form of grain-coating illite. Superior reservoir quality is observed at Tolmount compared to adjacent areas, due to the preservation of dune facies, a hypothesized early gas emplacement and a relatively benign burial history. Current mapped gas initially-in-place estimates for the field are between 450 bcf and 800 bcf, with an estimated recovery factor between 70 and 90%. An initial four-well development is planned, with first gas expected in 2020.

Diagenesis of the shallow marine Fulmar Formation in the Central North Sea

Clay Minerals ◽  
1986 ◽  
Vol 21 (4) ◽  
pp. 537-564 ◽  
Author(s):  
D. J. Stewart
Keyword(s):  
Clay Mineral ◽  
North Sea ◽  
Large Scale ◽  
Shear Zones ◽  
Upper Jurassic ◽  
Burial Diagenesis ◽  
Secondary Porosity ◽  
Shallow Marine ◽  
History Of ◽  
Central North Sea

AbstractThe diagenetic history of the Upper Jurassic Fulmar Formation of the Central North Sea is described with emphasis on the Fulmar Field. The Fulmar Formation was deposited on a variably subsiding shallow-marine shelf under the influence of halokinetic and fault movements. The sediments are extensively bio-destratified although large-scale cross-bedding is locally preserved. The dominant mechanism of deposition is thought to have been storm-generated currents. Soft-sediment deformation structures are common and are attributed to syn- and post-depositional dewatering of the sandstones. The dewatering was associated with fractures and shear zones which reflect tectonic instability resulting from periodic salt withdrawal and/or graben fault movements. The dewatering may have been initiated by repacking of the sediments during earth movements or by the gradual build-up and sudden release of overpressures due to compaction and/or clay mineral dehydration during rapid burial at the end of the Cretaceous. The formation is composed of arkosic sandstone of similar composition to Triassic sandstones from which it was probably derived. The sandstones also contain limited amounts of marine biogenic debris including sponge solenasters, bivalve shells, rare ammonites and belemnites. Initial diagenesis began with an environment-related phase during which quartz and feldspar overgrowths and chalcedony and calcite cements were precipitated. These cements appear to form concretions adjacent to local concentrations of sponge debris and shell debris, respectively, and were disturbed after their formation by fracturing and dewatering. This was followed by an early burial stage of diagenesis which resulted in extensive dolomite cementation and minor clay mineral authigenesis (illite and chlorite). The last phase of mineral growth was probably pyrite. During early burial diagenesis, secondary porosity after feldspar and/or carbonate was produced, although the exact timing is not clear. The lack of both stylolitic developments and extensive illitization indicates that the late burial diagenesis stage was never reached, although sufficient clay diagenesis occurred to destroy all traces of mixed-layer illite-smectite (present in some shallower wells). The main control on reservoir behaviour is primary depositional fabric. Diagenesis only overprints these controls. Locally-cemented fracture sets act as baffles to fluid flow, but they are not extensive and the reservoir acts as one unit.

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 Tyne Gas Fields, Block 44/18a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 851-860 ◽  
Author(s):  
P. T. O'Mara ◽  
M. Merryweather ◽  
D. S. Cooper
Keyword(s):  
North Sea ◽  
Water Depth ◽  
Water Contact ◽  
Reservoir Sandstones ◽  
Gas Fields

abstractThe Tyne Fields, operated by ARCO British Limited, are located within UKCS Block 44/18a, situated 180km off the Yorkshire coast in a water depth of 65 ft. The fields comprise three separate accumulations, each with a different gas-water contact and varying gas compositions, which are known as Tyne North, Tyne South and Tyne West. The three accumulations are combined structural and stratigraphical traps. The reservoir sandstones are of the Lower Ketch member of the Schooner Formation and are Carboniferous Westphalian C/D in age. The fields have been developed through long reach development wells.

scholarly journals Diagenetic impact on reservoir sandstones of the Heno Formation in the Ravn-3 well, Danish Central Graben

2018 ◽  
pp. 9-12
Author(s):  
Simone Pedersen ◽  
Rikke Weibel ◽  
Peter N. Johannessen ◽  
Niels H. Schovsbo
Keyword(s):  
North Sea ◽  
Middle Jurassic ◽  
Oil And Gas ◽  
Mineralogical Composition ◽  
Upper Jurassic ◽  
Gas Production ◽  
Oil And Gas Production ◽  
Carbonate Cement ◽  
Porosity And Permeability ◽  
Reservoir Sandstones

Oil and gas production from siliciclastic reservoirs has hitherto been in the Danish Central Graben mostly from Palaeogene and Middle Jurassic sandstone. The Ravn field was the first Upper Jurassic field to start operation. The reservoir is composed of sandstone of the Heno Formation. Production takes place at a depth of 4000 m, which makes Ravn the deepest producing field in the Danish North Sea. The Heno Formation mainly consists of marine shoreface deposits, where foreshore, middle and lower shoreface sandstones constitute the primary reservoir. The results of this study of the diagenetic impact on the mineralogical composition, porosity and permeability are presented here. Microcrystalline quartz has preserved porosity in the sandstone, whereas illite, quartz overgrowth and carbonate cement have reduced both porosity and permeability.

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