Reservoir quality and its relationship to facies and provenance in Middle to Upper Jurassic sequences, northeastern North Sea

Clay Minerals ◽  
2000 ◽  
Vol 35 (1) ◽  
pp. 77-94 ◽  
Author(s):  
M. Ramm
Keyword(s):  
Grain Size ◽  
North Sea ◽  
Close Relationships ◽  
Upper Jurassic ◽  
Reservoir Quality ◽  
Burial History ◽  
Deep Burial ◽  
Porosity And Permeability ◽  
Reservoir Sandstones ◽  
Initial Texture

AbstractClose relationships are demonstrated between reservoir quality, lithofacies, provenance and burial history in the Jurassic Brent and Viking Groups in the Norwegian North Sea. Porosity and permeability are strongly and systematically related to the initial texture and composition of the sandstones. Porosity variations are related to the amount of compaction, which is more severe in matrix-rich than in clean facies, and quartz cementation, which is most important in clean facies. Permeability variations are related to porosity and facies-controlled variations in grain size, and abundance and texture of intergranular fines. Illitization of early diagenetic kaolins require K, which is derived mainly from dissolution of K-feldspar. Sediments were sourced from K-feldspar- poor provenances during the maximum progradation of the Brent Group, and sandstones deposited at this time are less exposed to illitization and have better permeability at deep burial than reservoir sandstones that initially contained more K-feldspar.

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.

scholarly journals Diagenesis influencing the porosity of Upper Jurassic reservoir sandstones, Danish North Sea

2008 ◽  
Vol 15 ◽  
pp. 9-12 ◽  
Author(s):  
Rikke Weibel ◽  
Nynke Keulen
Keyword(s):  
North Sea ◽  
Source Area ◽  
Upper Jurassic ◽  
Burial History ◽  
Reservoir Properties ◽  
Thin Sections ◽  
The North ◽  
Diagenetic Alteration ◽  
The North Sea ◽  
Reservoir Sandstones

Upper Jurassic quartz-rich sandstones in the North Sea Basin are important reservoir rocks for oil and gas, and one of the latest discoveries of oil in the Danish sector was made in the area of the Hejre wells that penetrated such sediments (Fig. 1). The reservoir properties of sandstones are strongly influenced by diagenetic alteration, i.e. the mineralogical changes that take place during burial of the sediments. The diagenetic features depend on the source area, depositional setting, facies architecture and burial history of the sediment. The major diagenetic features influencing porosity in Upper Jurassic reservoir sandstones are feldspar dissolution and precipitation, preci-pitation of illite, calcite and quartz, and quartz stylolite formation. With regard to the Upper Jurassic sandstones in the Danish sector of the North Sea, the important question is: how can porosity be preserved in sediments buried at depths of more than 5 km? The Hejre-2 well penetrated the Upper Jurassic sediments (Fig. 2) before reaching pre-Upper Jurassic volcaniclastic conglomerates. The diagenetic features were studied in thin sections of core samples with traditional petrographic techniques using transmitted light microscopy supplemented by scanning electron microscopy (SEM) of rock chips and thin sections.

scholarly journals Small-scale diagenetic facies heterogeneity controls porosity and permeability pattern in reservoir sandstones

2020 ◽  
Vol 79 (18) ◽  
Author(s):  
Matthias Heidsiek ◽  
Christoph Butscher ◽  
Philipp Blum ◽  
Cornelius Fischer
Keyword(s):  
Reservoir Rock ◽  
Rock Properties ◽  
Small Scale ◽  
Reservoir Quality ◽  
Permian Basin ◽  
Gas Reservoirs ◽  
Spatial Fluctuations ◽  
Porosity And Permeability ◽  
Reservoir Sandstones ◽  
Diagenetic Facies

Abstract The fluvial-aeolian Upper Rotliegend sandstones from the Bebertal outcrop (Flechtingen High, Germany) are the famous reservoir analog for the deeply buried Upper Rotliegend gas reservoirs of the Southern Permian Basin. While most diagenetic and reservoir quality investigations are conducted on a meter scale, there is an emerging consensus that significant reservoir heterogeneity is inherited from diagenetic complexity at smaller scales. In this study, we utilize information about diagenetic products and processes at the pore- and plug-scale and analyze their impact on the heterogeneity of porosity, permeability, and cement patterns. Eodiagenetic poikilitic calcite cements, illite/iron oxide grain coatings, and the amount of infiltrated clay are responsible for mm- to cm-scale reservoir heterogeneities in the Parchim formation of the Upper Rotliegend sandstones. Using the Petrel E&P software platform, spatial fluctuations and spatial variations of permeability, porosity, and calcite cements are modeled and compared, offering opportunities for predicting small-scale reservoir rock properties based on diagenetic constraints.

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 relationship between synsedimentary fault activity and reservoir quality — A case study of the Ek1 formation in the Wang Guantun area, China

2020 ◽  
Vol 8 (3) ◽  
pp. SM15-SM24 ◽  
Author(s):  
Xixin Wang ◽  
Yuming Liu ◽  
Jiagen Hou ◽  
Shaohua Li ◽  
Qiangqiang Kang ◽  
...  
Keyword(s):  
Grain Size ◽  
Slip Rate ◽  
Size Analysis ◽  
Reservoir Quality ◽  
Accommodation Space ◽  
Controlling Mechanism ◽  
Porosity And Permeability ◽  
Fault Interpretation ◽  
The Relationship

The activity of synsedimentary faults plays an important role in controlling the distribution of sand bodies in basins and furthermore the porosity and permeability of reservoirs. We have used fault interpretation, the method of image and granularity size analysis, and the seismic pumping effect to investigate the control of the activity of the Kongdong fault on the development degree of the dissolution pores and grain size, further studying the controlling mechanism of the activity of synsedimentary faults on reservoir quality (porosity and permeability). The results showed that the slip rate of synsedimentary faults is one of the main factors in controlling reservoir quality. The slip rate controls the accommodation space and hydrodynamic conditions and it furthermore controls the grain size. The higher the slip rate, the bigger the grain size in the downthrow wall of synsedimentary faults; the seismic pump produced by synsedimentary faults activity also controls the development degree of dissolution pores. The development degree of dissolution pores in the downthrown wall of synsedimentary faults is greater than that in the upthrown wall. Dissolution pores are more developed in areas with a large slip rate of synsedimentary faults. Porosity increases gradually with the increase of plane porosity of dissolution pores, whereas the changes of permeability are not obvious.

The Osprey Field, Blocks 211/18a & 211/23a, UK North Sea*

1991 ◽  
Vol 14 (1) ◽  
pp. 183-189 ◽  
Author(s):  
John W. Erickson ◽  
C. D. Van Panhuys
Keyword(s):  
Crude Oil ◽  
North Sea ◽  
Water Depth ◽  
Middle Jurassic ◽  
Reservoir Quality ◽  
Shetland Islands ◽  
Delta System ◽  
Reservoir Sandstones ◽  
Northern North Sea ◽  
The Uk

AbstractThe Osprey Oilfield is located 180 km northeast of the Shetland Islands in Blocks 211/23a and 211/18a in the UK sector of the northern North Sea. The discovery well 211/23-3 was drilled in January 1974 in a water depth of 530 ft. The trap is defined at around 8500 ft TVSS by two dip and fault closed structures, the main 'Horst Block' and the satellite 'Western Pool'. The hydrocarbons are contained in reservoir sandstones belonging to the Middle Jurassic Brent Group which was deposited by a wave-dominated delta system in the East Shetlands Basin. The expected STOIIP and ultimate recovery are estimated at 158 MMBBL and 60 MMBBL of oil respectively, which represents a recovery factor of 38%. The 'Horst Block' contains 85% of the reserves with an OOWC about 150 ft shallower than in the 'Western Pool'. Reservoir quality is excellent, with average porosities varying from 23-26% and average permeabilities varying from 35-5300 md. The development plan envisages eleven satellite wells, six producers and five water injectors, closely clustered around two subsea manifolds. First production is expected in late 1990/early 1991. The wet crude oil will be piped to the Dunlin 'A' platform for processing and from there to the Cormorant Alpha platform into the Brent System pipeline for export to the Sullom Voe terminal.

Diagenetic controls on reservoir quality in Middle to Upper Jurassic sandstones in the South Viking Graben, North Sea

AAPG Bulletin ◽  
2011 ◽  
Vol 95 (11) ◽  
pp. 1937-1958 ◽  
Author(s):  
Tom Erik Maast ◽  
Jens Jahren ◽  
Knut Bjørlykke
Keyword(s):  
North Sea ◽  
Upper Jurassic ◽  
Reservoir Quality ◽  
The South

scholarly journals The Cavendish Field, Block 43/19, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 131-141 ◽  
Author(s):  
N. Wasielka ◽  
J. G. Gluyas ◽  
H. Breese ◽  
R. Symonds
Keyword(s):  
Grain Size ◽  
Continental Shelf ◽  
North Sea ◽  
Water Depth ◽  
Reservoir Quality ◽  
Low Permeability ◽  
Gas Field ◽  
Upper Carboniferous ◽  
Northern Margin

AbstractThe Cavendish Field is located in UK Continental Shelf Block 43/19a on the northern margin of the Outer Silverpit Basin of the Southern North Sea, 87 miles (140 km) NE of the Lincolnshire coast in a water depth of 62 ft (18.9 m). The Cavendish Field is a gas field in the upper Carboniferous Namurian C (Millstone Grit Formation) and Westphalian A (Caister Coal Formation) strata. It was discovered in 1989 by Britoil-operated well 43/19-1. Production started in 2007 and ceased in 2018. Gas initially in place was 184 bcf and at end of field life 98 bcf had been produced. The field was developed by three wells drilled through the normally unmanned platform into fluvio-deltaic sandstone intervals that had sufficiently good reservoir quality to be effective reservoirs. The majority of the formation within closure comprises mudstones, siltstones and low permeability, non-reservoir-quality feldspathic sandstones. The quality of the reservoir is variable and is controlled by grain size, feldspar content and diagenesis. The field is a structural trap, sealed by a combination of intra-Carboniferous mudstones and a thick sequence of Permian mudstones and evaporites.

scholarly journals Reservoir Quality of Upper Jurassic Corallian Sandstones, Weald Basin, UK

Geosciences ◽  
2021 ◽  
Vol 11 (11) ◽  
pp. 446
Author(s):  
Dinfa Vincent Barshep ◽  
Richard Henry Worden
Keyword(s):  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Upper Jurassic ◽  
Reservoir Quality ◽  
Main Process ◽  
Shallow Marine ◽  
Porosity And Permeability ◽  
Calcite Cement ◽  
Diagenetic Evolution

The Upper Jurassic, shallow marine Corallian sandstones of the Weald Basin, UK, are significant onshore reservoirs due to their future potential for carbon capture and storage (CCS) and hydrogen storage. These reservoir rocks, buried to no deeper than 1700 m before uplift to 850 to 900 m at the present time, also provide an opportunity to study the pivotal role of shallow marine sandstone eodiagenesis. With little evidence of compaction, these rocks show low to moderate porosity for their relatively shallow burial depths. Their porosity ranges from 0.8 to 30% with an average of 12.6% and permeability range from 0.01 to 887 mD with an average of 31 mD. The Corallian sandstones of the Weald Basin are relatively poorly studied; consequently, there is a paucity of data on their reservoir quality which limits any ability to predict porosity and permeability away from wells. This study presents a potential first in the examination of diagenetic controls of reservoir quality of the Corallian sandstones, of the Weald Basin’s Palmers Wood and Bletchingley oil fields, using a combination of core analysis, sedimentary core logs, petrography, wireline analysis, SEM-EDS analysis and geochemical analysis to understand the extent of diagenetic evolution of the sandstones and its effects on reservoir quality. The analyses show a dominant quartz arenite lithology with minor feldspars, bioclasts, Fe-ooids and extra-basinal lithic grains. We conclude that little compactional porosity-loss occurred with cementation being the main process that caused porosity-loss. Early calcite cement, from neomorphism of contemporaneously deposited bioclasts, represents the majority of the early cement, which subsequently prevented mechanical compaction. Calcite cement is also interpreted to have formed during burial from decarboxylation-derived CO2 during source rock maturation. Other cements include the Fe-clay berthierine, apatite, pyrite, dolomite, siderite, quartz, illite and kaolinite. Reservoir quality in the Corallian sandstones show no significant depositional textural controls; it was reduced by dominant calcite cementation, locally preserved by berthierine grain coats that inhibited quartz cement and enhanced by detrital grain dissolution as well as cement dissolution. Reservoir quality in the Corallian sandstones can therefore be predicted by considering abundance of calcite cement from bioclasts, organically derived CO2 and Fe-clay coats.

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