DEPOSITION AL AND DIAGENETIC CONTROLS ON THE QUALITY OF BARROW GROUP SANDSTONE RESERVOIRS, BARROW SUB-BASIN, NORTH WEST SHELF, WESTERN AUSTRALIA

1997 ◽  
Vol 37 (1) ◽  
pp. 214 ◽  
Author(s):  
G. M. Kraishan ◽  
N. M. Lemon ◽  
P.R. Tingate
Keyword(s):  
Grain Size ◽  
Fine Sand ◽  
Potassium Feldspar ◽  
Coarse Grained ◽  
Reservoir Quality ◽  
Secondary Porosity ◽  
Intergranular Porosity ◽  
North West ◽  
Mechanical Compaction

The main controls on Barrow Group reservoir quality are depositional (lithofacies) and post depositional (di- agenetic). Barrow Group sediments were deposited in environments ranging from non-marine to deep marine. The upper sandstones (Flacourt Formation) in the centra] and southern parts of the sub-basin are dominantly of good reservoir quality, consisting mainly of marine- reworked strandplain and shoreface deposits. The lower sandstones (Malouet Formation), however, in the Barrow Sub-basin depocentre, are composed predominantly of slope apron deposits, consisting of tight, matrix-rich, non-productive sandstones. The Flag Sandstone, distributed along the northern part of the sub-basin, is made up mainly of mounded turbidite deposits consisting of excellent reservoir quality, coarse-grained sheet turbid-ites.Petrographic observations of theliarrow Group show that sands are, in general, extremely well sorted and display a unimodal grain-size distribution. Grain size varies slightly with the depositional environment; the mounded turbidite sandstones average 197 f.im (fine sand) and the slope apron sandstones average 185 pm (fine sand). The grain size in the marine-reworked strandplain sandstones averages 300 j.im (medium sandstones). Detrital depositional matrix, mechanical compaction and cementation are the main causes of poor reservoir quality. Mechanical compaction is responsible for destroying up to 60 per cent of the original porosity. Chemical compaction has had much less effect. Precipitation of authigenic minerals has reduced, on average, the primary intergranular porosity to 12 per cent of the whole rock-volume.In some cases, secondary porosity development has greatly enhanced the reservoir quality of the Barrow Sub-basin sandstones. It results from dissolution of calcite, dolomite and potassium feldspar. Reservoir quality is most improved along the margins of the sub-basin as this is where carbonate and feldspar were most abundant.

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.

FAULT-RELATED CALCITE CEMENTATION: IMPLICATIONS FOR TIMING OF HYDROCARBON GENERATION AND MIGRATION AND SECONDARY POROSITY DEVELOPMENT, BARROW SUB BASIN, NORTHWEST SHELF

2000 ◽  
Vol 40 (1) ◽  
pp. 213
Author(s):  
G.M. Kraishan ◽  
N.M. Lemon
Keyword(s):  
Carbon Isotopic Composition ◽  
Reservoir Quality ◽  
Hydrocarbon Generation ◽  
Pore Waters ◽  
Secondary Porosity ◽  
North West ◽  
Carbon Isotopic ◽  
Authigenic Mineral ◽  
And Migration ◽  
Primary Porosity

Calcite is a common authigenic mineral in subsurface sandstones of the Barrow Sub-basin, North West Shelf. It is present in several formations from different stratigraphic horizons, ranging from Permian to Cretaceous. It occurs as poikilotopic cement and fracture-fill particularly concentrated along one of the major listric faults in the eastern part of the sub-basin. A detailed petrographical and geochemical study was performed on the Early Cretaceous calcite cements in an attempt to provide information on their origin, distribution and effect on reservoir quality. Calcite cements are Ca-rich, Mg-poor with considerable amounts of Fe and are characterised by bright orange to yellow luminescent colours. The δ13C and δ180 values vary considerably, δ13C ranging from −2.0 to −23.5 %o PDB (average of −10.2 %o, ± 4.8 PDB), whilst δ180 values range from 19.3 to 25.4 SMOW (average of 21.1 %o, ± 1.8 SMOW). Calcite cements are characterised by elevated 87Sr/86Sr ratios with a range of 0.71029 to 0.71058 (average of 0.71043 ± 0.00012). The elemental and stable isotope compositions of the calcite cements indicate cementation from meteoric pore-waters, with the same source and timing of occurrence.Calcite cements formed in the mid-diagenetic history below 45°C. The carbon isotopic composition of calcite cements is interpreted to be sourced from bicarbonate and carbon dioxide generated by thermal decarboxylation of kerogen and oxidation of the early-generated oil. The model for calcite formation involves fluids rich in organic carbon having migrated up dip along faults to be trapped and mixed with meteoric-derived C02 to form pervasive calcite-cemented zones. These zones may reach up to 8 m thick and occlude the intergranular primary porosity. Subsequent tectonic reactivation and maturation of organic matter has resulted in late acidic water invasion to partially or completely dissolve the calcite cement to locally enhance reservoir quality.

Controls on the reservoir quality of Late Cretaceous Springar Formation deep-water fan systems in the Vøring Basin

2017 ◽  
Vol 8 (1) ◽  
pp. 247-257 ◽  
Author(s):  
Alana Finlayson ◽  
Angela Melvin ◽  
Alex Guise ◽  
James Churchill
Keyword(s):  
Grain Size ◽  
Late Cretaceous ◽  
Clay Content ◽  
Coarse Grained ◽  
Reservoir Quality ◽  
Low Permeability ◽  
Quality Model ◽  
Depositional Facies ◽  
Porosity And Permeability ◽  
Vøring Basin

AbstractA new reservoir quality model is proposed for the Late Cretaceous Springar Formation sandstones of the Vøring Basin. Instead of a depth-related compactional control on reservoir quality, distinct high- and low-permeability trends are observed. Fan sequences which sit on the high-permeability trend are characterized by coarse-grained facies with a low matrix clay content. These facies represent the highest energy sandy turbidite facies within the depositional system, and were deposited in channelized or proximal lobe settings. Fan sequences on the low-permeability trend are characterized by their finer grain size and the presence of detrital clay, which has been diagenetically altered to a highly microporous, illitic, pore-filling clay. These fan sequences are interpreted to have been deposited in proximal–distal lobe environments. Original depositional facies determines the sorting, grain size and detrital clay content, and is the fundamental control on reservoir quality, as the illitization of detrital clay is the main mechanism for reductions in permeability. Core-scale depositional facies were linked to seismic-scale fan elements in order to better predict porosity and permeability within each fan system, allowing calibrated risking and ranking of prospects within the Springar Formation play.

DIAGENESIS AND THE EVOLUTION OF GIPPSLAND BASIN RESERVOIRS

1984 ◽  
Vol 24 (1) ◽  
pp. 314 ◽  
Author(s):  
J. M. Bodard ◽  
V. J. Wall ◽  
R. A. F. Cas
Keyword(s):  
Sedimentary Basins ◽  
Coarse Grained ◽  
Rock Fragment ◽  
Reservoir Quality ◽  
Fluid Migration ◽  
High Porosity ◽  
Secondary Porosity ◽  
Porosity Reduction ◽  
Gippsland Basin ◽  
Dolomite Precipitation

Key findings of this study on the nature, distribution and influences of diagenetic modifications to the Latrobe Group, Gippsland Basin, are: The Latrobe Group sandstones do not exhibit the regular porosity/depth patterns regarded as typical for many sedimentary basins. Dolomite cements are widely though variably developed in sandstones that are characteristically medium-to very coarse-grained, matrix-poor, texturally and mineralogically mature. These cements fill pore spaces, exhibit partial framework replacive textures, and may comprise as much as 30 per cent of total rock volume. In Flounder, Snapper, Tuna, Marlin, and probably other fields dolomite cementation is the major cause of porosity reduction. Sandstone porosity, notably in the above examples, is largely secondary and principally derived from the dissolution of precursor dolomite cements. Advanced dissolution results in exceptionally high porosity and permeability, and is largely responsible for the character of Snapper, Marlin, Tuna, Flounder and probably other reservoirs. Dedolomitization appears to be closely associated with hydrocarbon emplacement. Another important form of secondary porosity, developed in sandstones lacking evidence of extensive dolomitization, results from the dissolution of clay matrix. This contributes significantly to Mackerel. Hapuku, Kingfish and Halibut reservoir quality. Feldspar and rock fragment dissolution and alteration, as well as intra-clast fracturing, also contribute minor secondary porosity. Secondary porosity may subsequently be reduced by authigenic kaolinite (with or without illite) and rare chlorite filling, quartz cementation, framework restructuring and compaction, such as is typical of Bream, deeper Barracouta, Snapper, Tuna and other deeper arenite strata. Chemical modelling of the interaction between dolomite and aqueous fluids indicates that large volumes of fluid are necessary to effect dolomite precipitation and dissolution. Variation in pH and Pco2 related to fluid migration and subsurface mixing are evidently the controlling variables. Carbon and oxygen stable isotope data are compatible with dolomite precipitation from largely non-marine fluids containing organically sourced carbon species. Systematic lithological, spatial, depth and/or thermally related patterns of diagenetic modification are recognized on a basin-wide scale. In view of the significant role diagenetic processes have played in the evolution of hydrocarbon reservoirs, an understanding of their relationship to fluid migration and organic maturation is important to future exploration. In conjunction with knowledge of basin tectonics, thermal and sedimentological history, this understanding is fundamental to developing models which predict porosity trends and reservoir quality in the Gippsland and other sedimentary basins.

Sedimentary provinces of the fishing grounds of the North West Shelf of Australia: Grain-size frequency analysis of surficial sediments

1985 ◽  
Vol 36 (5) ◽  
pp. 671 ◽  
Author(s):  
RJ McLoughlin ◽  
PC Young
Keyword(s):  
Grain Size ◽  
Frequency Analysis ◽  
Fine Sand ◽  
Carbonate Content ◽  
North West ◽  
North East ◽  
The North ◽  
Size Frequency ◽  
Sediment Types ◽  
Shelf Slope

As part of a multidisciplinary study of the continental shelf of north-west Australia, 354 sediment samples were taken to describe the distribution of sedimentary provinces contained within the region. A grain-size frequency analysis and subsequent classification have revealed six principal sediment types roughly corresponding to an east-west and inshore-offshore distribution. The study area is characterized by coarse skeletal detritus in the south-west, with a transition to a significant accretionary carbonate component in the form of oolites, pellets and infilled biogenic particles in the north-east. Superimposed on this pattern is a decrease in grain size from shallow to deeper waters, culminating in carbonate muds on the shelf slope. Carbonate content of sediments is uniformly high, ranging from 60 to 100% of the total weight of all samples. Non-carbonate material is principally clay; however, small quantities (less than 1%) of fine sand-size angular quartz are present.

DEFOSITIONAL FRAMEWORK AND DIAGENESIS OF THE LATE PERMIAN GAS RESERVOIRS OF THE BONAPARTE BASIN

1984 ◽  
Vol 24 (1) ◽  
pp. 299 ◽  
Author(s):  
M. R. Bhatia ◽  
M. Thomas ◽  
J. M. Boirie
Keyword(s):  
Clay Content ◽  
Coarse Grained ◽  
Reservoir Quality ◽  
Late Permian ◽  
Gas Reservoirs ◽  
Delta Front ◽  
Delta Plain ◽  
Porosity And Permeability ◽  
Calcite Cementation

Late Permian sandstones form the reservoir of the Tern and Petrel gas fields in the offshore Bonaparte Basin. The producing reservoirs of the Petrel field were deposited in various environments associated with a major northwesterly trending deltaic system. The producing sands in the Tern field were deposited in the shoreface environment of a barrier-bar system.The reservoir quality of the sands is controlled by the diagenesis, which is facies dependent. In the Petrel field, sandstones deposited in the upper delta plain and along the shoreline are clean, medium-to coarse-grained and highly quartzose but have very low porosity and permeability due to extensive quartz diagenesis. However, sands deposited in delta front and lower delta plain environments are medium to fine grained, argillaceous and have fair to good reservoir potential. In these sands, the dispersed clays formed coats and rims on quartz grains during early diagenesis and inhibited quartz overgrowth. In the Tern field, sands of the upper shoreface have poor reservoir quality due to early calcite cementation. However, finer-grained sandstones of the lower shoreface facies have good reservoir quality. The porosity in these sands is mainly primary and preserved due to low carbonate and high clay content. The processes of quartz and calcite cementation which drastically reduced the reservoir quality of the coarse-grained sands occurred early and were influenced by the texture of the sands and probably also by the chemical character of the formation waters.

scholarly journals Rock Physics Modelling for Estimating the Quality of Reservoir Tight Sand in Bintuni Basin, West Papua, Indonesia

2018 ◽  
Vol 16 (3) ◽  
pp. 14
Author(s):  
Dona Sita Ambarsari ◽  
S. Winardhi
Keyword(s):  
Grain Size ◽  
Surface Area ◽  
Pore Space ◽  
Rock Physics ◽  
Reservoir Quality ◽  
Elastic Parameters ◽  
Critical Porosity ◽  
Rock Quality

Permeability is a key to determine the quality of reservoir. Reservoir quality can be dened as the ratio between permeability and porosity of a rock. Besides, permeability is not in uenced by porosity solely, there are otherfactors which aect the value of the permeability of a rock. One of them is aected by the pore structure, which includes turtuosity, surface area, and grain size. To determine how much these factors aect the permeability of a rock, it takes an elastic parameters that can be an indicator of the quality reservoir e.g pore space stiness and critical porosity.Primary data such as petrophysics, XRD data, and permeability are used as input data to determine the quality of reservoir. By using Zimmerman's equation and Nur's model, we will get the value of pore space stiness and critical porosity at each point. The combination of rock quality equation derived from Kozeny Carman's with elastic parameters as indicators produces qualitative rock quality identification. Results of this study is able to show that the pore space stiffness and critical porosity can represent turtuosity, surface area, and grain size of a rock which lead to the determination of rock quality. The method proposed in the present study demonstrated an excellence reservoir quality prediction based on the relation between petrophysical parameters with elastic parameters.

scholarly journals Diagenetic controls on reservoir quality of tight sandstone: A case study of the Upper Triassic Yanchang formation Chang 7 sandstones, Ordos Basin, China

2018 ◽  
Vol 22 (2) ◽  
pp. 129-138 ◽  
Author(s):  
Haihua Zhu ◽  
Guangchen Liu ◽  
Dakang Zhong ◽  
Tingshan Zhang ◽  
Jun Lang ◽  
...  
Keyword(s):  
Late Stage ◽  
Ordos Basin ◽  
Mineral Dissolution ◽  
Reservoir Quality ◽  
Tight Sandstone ◽  
Pore Characteristics ◽  
Mechanical Compaction ◽  
Primary Porosity ◽  
The Impact

Through a range of petrological techniques, the petrology, diagenesis, pore characteristics, and controlling factors on the regional variations of reservoir quality of the Chang 7 sandstones were studied. These sandstones, mainly arkoses, lithic arkoses, and feldspathic litharenites, were deposited in a delta front and turbidites in semi-deep to deep lacustrine. The detrital constituents were controlled by the provenance and sedimentary condition, which resulted in a spatially variable composition; e.g., high biotite and feldspar contents in the northeast (NE) of the study area, and high contents of rock fragments, especially dolomite, matrix, and quartz in the southwest (SW). Diagenesis includes intense mechanical compaction, cementation, and dissolution of unstable minerals. Diagenetic minerals which were derived internally include quartz, ankerite, ferrous calcite, albite, illite, kaolinite, and chlorite. Thus the original sandstone composition hadfirm control over the development and distribution of cement. Mechanical compaction and late-stage cementations contribute to the porosity loss of sandstones of Chang7 member. The dissolution porosity in major sandstone, slightly higher than primary porosity is principally dependent on the accessibility of acid fluid. The high content of plastic component facilitated the reduction of primary porosity and limited the mineral dissolution. The best reservoir sandstones are found in W, and partly from NE, M districts, with porosity are primary. The relatively high textural maturity of these sandstones reduces the impact of compaction on primary pores, and commonly existed chlorite rims limited the precipitation of pore filling quartz and carbonate cementation in late stage.

scholarly journals Hydrocarbon Source and Reservoir Rock Potential of the Paleocene Hangu Formation in the Himalayan Foreland Basin, North West Pakistan: Insight from Geochemical and Diagenetic Study

2019 ◽  
Vol 62 (3) ◽  
pp. 157-166
Author(s):  
Kamil Ahmed Qureshi ◽  
Hamid Hussain ◽  
Afsar Ali Shah ◽  
Ishaque Ali Meerani ◽  
Shah Fahad ◽  
...  
Keyword(s):  
Iron Oxide ◽  
Source Rock ◽  
Reservoir Rock ◽  
Coarse Grained ◽  
Carbonaceous Shale ◽  
Reservoir Properties ◽  
North West ◽  
Type Iii ◽  
Mechanical Compaction ◽  
Immature Source Rock

The detail study of the Paleocene Hangu Formation consisting of sandstone, carbonaceous shale, coal, and laterite has been carried out for its source and reservoir rock potential in the Salt Range, Surghar Range, and Attock-Cherat Ranges. The TOC values of the shales range from 0.33-11.19 (2.97 wt. %) and are characterized as good to very good quality source rock except the samples from Attock-Cherat Ranges. Similarly, the free (S1) and cracked hydrocarbons (S2) amount are very small suggesting Hangu Formation as a poor source rock for free and cracked hydrocarbons except the samples from the Lumshiwal Nala. The generative potential, type of kerogen and thermal maturity calculated on the basis of TOC, S1, S2, HI, PI and Tmax all characterized Hangu Formation as fair to excellent gas or oil source, type III and mixed type III/II kerogen and immature source rock. The Hangu Formation sandstone is brownish to yellowish brown, fine to coarse grained, medium to thick bedded and massive in places. The major diagenetic changes observed in a sandstone of the Hangu Formation are; compaction, cementation, replacement and grain fracturing. The effect of mechanical compaction is more evident than that of chemical compaction. Grain contact ranges from pointed to long through sutured. The type of cement present includes silica-cement, calcite-cement, dolomite-cement, and iron-oxide cement. Silica-cement is present as both overgrowth and pore-filling cement. Clay rim is present around few grains. The process of early calcite cementation, mechanical compaction, silica, and iron oxide cementation destroys the reservoir properties of the Hangu Formation sandstone. There is no visible porosity observed except the dissolution of few grains at their margins. However, during the process of uplifting such porosity usually filled by the iron- oxide cementation. Hence, Hangu Formation is an immature source rock with a poor reservoir potential.  

scholarly journals PETROGRAPHIC CHARACTERIZATION AND DIAGENESIS IN SANDSTONES OUTCROPS OF THE NORTHERN MACEIÓ FORMATION: IMPLICATIONS IN RESERVOIR QUALITY

2021 ◽  
Vol 15 (1-2) ◽  
pp. 37-52
Author(s):  
M. S. C. Tenório ◽  
Z. V. Batista ◽  
G. M. D. Fernandes
Keyword(s):  
Potential Method ◽  
Reservoir Quality ◽  
Petrographic Analysis ◽  
Northern Coast ◽  
Secondary Porosity ◽  
Diagenetic Processes ◽  
Geological Unit ◽  
Northern Portion ◽  
Primary Porosity

The acquisition of geological data is of fundamental importance for the study of areas potentially relevant to the occurrence of petroleum systems. In this context, the development of research in outcropping rock formations has proven to be a potential method to investigate the geology of the geological unit studied in subsurface. One of several examples found in Brazil are the outcrops Barreiras do Boqueirão and Praia de Japaratinga, belonging to the Maceió Formation, located in the northern coast of Alagoas State. The Maceió Formation has the lowest cretaceous sedimentation record within the Alagoas Basin. This sedimentation, present almost in the entire basin, is located mainly in its subsurface. This geological unit is composed of several lithologies, including a turbiditic sequence predominantly formed by shales, sandstones and conglomerates. This environment makes it possible the occurrence of a petroleum system. Our research group chose to investigate this environment because turbiditic sandstones are excellent petroleum reservoirs, and they have a great economic relevance in the Brazilian petroleum scenario. To develop this research, a petrographic characterization of the Maceió Formation sandstones was conducted to help determine the compositional and diagenetic aspects of these rocks and infer the influence of diagenetic processes on the quality of these sandstones as reservoirs. The petrographic analysis showed that the studied sandstones can be classified as arkose and quartzenite, present moderate porosity and good permeability, observed through the predominant presence of floating contacts between the grains. The porosity is predominantly primary intergranular, averaging 15%, but secondary porosity by fracture and dissolution of primary grains also occurs. The sandstones of the Maceió Formation are poorly and moderately selected, with angular, sub-angular and sub-rounded grains, showing low to medium textural maturity, which may also influence the quality of the reservoir, impairing the primary porosity in the samples. The three diagenetic stages were identified as: eodiagenesis, mesodiagenesis, and telodiagenesis. The diagenetic processes found were: mechanical compaction, beginning of chemical compaction, clay infiltration, pyrite cementation, grain dissolution, chlorite cementation, quartz sintaxial growth, and mineral alteration and replacement. Mineral replacement was a phenomenon observed quite expressively in the samples analyzed. This event was evidenced, particularly, by the substitution of muscovite and feldspar for kaolinite, the alteration of biotite was also identified in the samples. Therefore, one can infer that the diagenetic processes had little influence on the reduction of the original porosity in the samples studied. In general, considering all the analyses performed in this research, one can see that the sandstones of the Maceió Formation (northern portion) present a good reservoir quality.

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