scholarly journals Diagenesis of the Zechstein Ca-2 carbonate from the Løgumkloster-1 well, Denmark

1990 ◽  
Vol 12 ◽  
pp. 1-42
Author(s):  
Niels Stentoft
Keyword(s):  
Carbonate Platform ◽  
Pore Geometry ◽  
Reservoir Quality ◽  
Carbonate Sediments ◽  
Complex Sequence ◽  
The North ◽  
Depositional Evolution ◽  
Diagenetic Evolution ◽  
Intercrystalline Porosity

The carbonate unit Ca-2 found in the Løgumkloster-l well is located on the northern marginal carbonate platform of the North German Zechstein Basin. The ea. 43 m thick sequence includes former oncoidal/algal muds which were deposited in a relatively quiet lagoonal back-barrier environment, and ooidal carbonate sands, deposited in a rather agitated shoal environment. The carbonate sediments of Ca-2 have been subjected to a complex sequence of diagenetic events. However, the present porosity/ permeability, and thus the reservoir quality of the rocks, is primarily linked to four events: two leaching phases, a phase of chemical compaction, and a late anhydritization. The first phase of leaching created mouldic porosity. The last phase of leaching was important as it resulted in a widening of the preexisting pores and fractures and thereby facilitated percolation of sulphate solutions causing the late anhydritization, which considerably reduced the porosity/ permeability of the rock. The present pore geometry of the rock is complex. In the oolitic intervals the intra- and inter-ooidal porosity types are the most widespread. In the oncolitic/algal intervals intra- and inter-oncoidal porosity and vuggy porosity are often combined with intercrystalline porosity. The corresponding Ca-2 rock in the Brøns-l well, situated ca. 20 km northwest of the Løgumkloster- l well, was subjected to the same post-depositional evolution. Comparison with the diagenesis of the upper part of the Ca-la formation in the Aabenraa-1 well and the Ca-1 formation of the Varmes-1 well also shows close similarity in the diagenetic evolution.

Depositional facies, diagenetic clay minerals and reservoir quality of Rotliegend sediments in the Southern Permian Basin (North Sea): a review

Clay Minerals ◽  
1982 ◽  
Vol 17 (1) ◽  
pp. 55-67 ◽  
Author(s):  
U. Seemann
Keyword(s):  
Clay Minerals ◽  
North Sea ◽  
Effective Porosity ◽  
Hydrocarbon Exploration ◽  
Reservoir Quality ◽  
Burial Diagenesis ◽  
Permian Basin ◽  
Northern Margin ◽  
The North

AbstractThe Southern Permian Basin of the North Sea represents an elongate E-W oriented depo-centre along the northern margin of the Variscan Mountains. During Rotliegend times, three roughly parallel facies belts of a Permian desert developed, these following the outline of the Variscan Mountains. These belts were, from south to north, the wadi facies, the dune and interdune facies, and the sabkha and desert lake facies. The bulk of the gas reservoirs of the Rotliegend occur in the aeolian dune sands. Their recognition, and the study of their geometry, is therefore important in hydrocarbon exploration. Equally important is the understanding of diagenesis, particularly of the diageneticaily-formed clay minerals, because they have an important influence on the reservoir quality of these sands. Clay minerals were introduced to the aeolian sands during or shortly after their deposition in the form of air-borne dust, which later formed thin clay films around the grains. During burial diagenesis, these clay films may have acted as crystallization nuclei for new clay minerals or for the transformation of existing ones. Depending on their crystallographic habit, the clay minerals can seriously affect the effective porosity and permeability of the sands.

scholarly journals The Evaluation of Reservoir Quality of Mishrif Formation in South and North Domes of Buzurgan Oil Field

2019 ◽  
Vol 9 (4) ◽  
pp. 89-106
Author(s):  
Ali Duair Jaafar ◽  
Dr. Medhat E. Nasser
Keyword(s):  
Physical Properties ◽  
Water Saturation ◽  
Oil Field ◽  
Reservoir Quality ◽  
Petrophysical Properties ◽  
The South ◽  
Reservoir Properties ◽  
Formation Evaluation ◽  
The North

Buzurgan field in the most cases regards important Iraqi oilfield, and Mishrif Formation is the main producing reservoir in this field, the necessary of so modern geophysical studies is necessity for description and interpret the petrophysical properties in this field. Formation evaluation has been carried out for Mishrif Formation of the Buzurgan oilfield depending on logs data. The available logs data were digitized by using Neuralog software. A computer processed interpretation (CPI) was done for each one of the studied wells from south and north domes using Techlog software V2015.3 in which the porosity, water saturation, and shale content were calculated. And they show that MB21 reservoir unit has the highest thickness, which ranges between (69) m in north dome to (83) m in south dome, and the highest porosity, between (0.06 - 0.16) in the north dome to (0.05 -0.21) in the south dome. The water saturation of this unit ranges between (25% -60%) in MB21 of north dome. It also appeared that the water saturation in the unit MB21 of south dome has the low value, which is between (16% - 25%). From correlation, the thickness of reservoir unit MB21 increases towards the south dome, while the thickness of the uppermost barrier of Mishrif Formation increases towards the north dome. The reservoir unit MB21 was divided into 9 layers due to its large thickness and its important petrophysical characterization. The distribution of petro physical properties (porosity and water saturation) has shown that MB 21 has good reservoir properties.

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.

Mapping porosity anomalies in deep Jurassic sandstones – an example from the Svane-1A area, Danish Central Graben

1969 ◽  
Vol 23 ◽  
pp. 13-16 ◽  
Author(s):  
Tanni Abramovitz
Keyword(s):  
High Pressure ◽  
High Temperature ◽  
Upper Jurassic ◽  
Reservoir Quality ◽  
Oil Accumulation ◽  
The North ◽  
The North Sea ◽  
Sandstone Reservoirs ◽  
High Temperature High Pressure

Hydrocarbon-bearing Upper Jurassic sandstone reservoirs at depths of more than 5000 m may form a future exploration target in the Danish Central Graben (Fig. 1). The Upper Jurassic sandstone play in the Danish sector has historically been less successful than in the neighbouring Norwegian and British sectors of the North Sea. This is mainly due to poor reservoir quality of the sandstones. However, the discovery in 2001 of an oil accumulation at a depth of more than 5000 m in the Svane-1 well has triggered renewed interest in the Upper Jurassic High Temperature – High Pressure (HTHP) sandstone play in Danish waters. The Jurassic plays comprise sandstone reservoirs deposited in a variety of environments, ranging from fluvial to deep marine.

GEOLOGICAL CONTROLS ON RESERVOIR QUALITY OF THE NORTHERN PERTH BASIN

1987 ◽  
Vol 27 (1) ◽  
pp. 318 ◽  
Author(s):  
S.L. Bergmark ◽  
P.R Evans
Keyword(s):  
High Energy ◽  
Reservoir Quality ◽  
Gas Field ◽  
Reservoir Rocks ◽  
The North ◽  
Fan Delta ◽  
The Common ◽  
Primary Porosity ◽  
And Control

The major onshore Dongara gas field and a number of adjacent minor gas and oil pools are reservoired in basal Triassic sandstones that are sealed by the overlying Kockatea Shale. Reservoir quality is found to be controlled primarily by the local provenance of the sandstones, by diagenesis and the regional palaeotopography. Sandstones east of Dongara are reworked products of a Late Permian fan delta (Wagina Sandstone) that extended westwards from the basin's eastern, fault controlled margin. Localised high energy streams drained the palaeoslope, depositing thin wedges of mainly fluvial sediments upon and around the flanks of the Permian fan delta during a regional rise in sea level in the Early Triassic. Sandstones to the north of Dongara are localised, low energy offshore bars and strandline deposits derived from Precambrian of the Northampton Block. Diagenetic alterations of the Triassic sandstones, also controlled by the sandstones' provenance, have substantially reduced primary porosity and control permeability. The common presence of the authigenic clay mineral, dickite, is taken as evidence that a fluvial environment of deposition controlled formation of the reservoir rocks.

scholarly journals Lithostratigraphy, Sedimentology and Hydrocarbon Habitat of the Pre-Cenomanian Nubian Sandstone in the Gulf of Suez Oil Province, Egypt

GeoArabia ◽  
1997 ◽  
Vol 2 (4) ◽  
pp. 385-400 ◽  
Author(s):  
Abdulrahman S. Alsharhan ◽  
Mohammed G. Salah
Keyword(s):  
Lower Cretaceous ◽  
Depositional Environments ◽  
Reservoir Quality ◽  
Gulf Of Suez ◽  
Carbonate Sediments ◽  
Nubian Sandstone ◽  
Diagenetic History ◽  
Depth Of Burial ◽  
Northern Sector

ABSTRACT The Paleozoic-Lower Cretaceous Nubian Sandstone is a thick sequence of up to 1,200 meters of clastic and thin carbonate sediments. In ascending order it is classified into the following groups and formations: Qebliat Group, Umm Bogma Formation, Ataqa Group and El-Tih Group. This sequence is composed mainly of sandstones with shale and minor carbonate interbeds and was deposited in continental and fluviomarine to marine settings. Petrographically, two main facies of Nubian Sandstone can be recognized in the Gulf of Suez: quartzarenite and quartzwackes. Both contain subfacies that are different in their secondary components, cement and matrix types, reflecting their different depositional environments and diagenetic histories. The pre-Cenomanian Nubian Sandstone is one of the most prolific reservoirs in the Gulf of Suez oil province. These sandstones have intervals with good reservoir quality throughout the basin, with net pay thickness of up to 450 meters, and net sand ratios ranging from 60% to 90%. Porosity varies from 10% to 29%, and permeability from 70-850 millidarcies. The quality of the reservoir depends on its shaliness, diagenetic history and the depth of burial (compaction). The Nubian Sandstone still has a high potential as a reservoir, particularly in the northern sector of the Gulf of Suez where few wells have specifically targeted this interval.

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