scholarly journals Small-Scale Diagenetic Heterogeneity Effects on Reservoir Quality of Deep Sandstones: A Case Study from the Lower Jurassic Ahe Formation, Eastern Kuqa Depression

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-25
Author(s):  
LiKuan Zhang ◽  
Xiaorong Luo ◽  
Mingze Ye ◽  
Baoshou Zhang ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Effective Properties ◽  
Lower Jurassic ◽  
Coarse Grained ◽  
Small Scale ◽  
Reservoir Quality ◽  
Thin Sections ◽  
Kuqa Depression ◽  
Porosity Evolution ◽  
Reservoir Rocks ◽  
Porosity And Permeability

The Lower Jurassic Ahe Formation is an important exploration target for deep clastic reservoirs in the eastern Kuqa Depression. The Ahe Formation sandstones show heterogeneous porosity and permeability petrophysical properties. These properties have been poorly understood, limiting forecast of petroleum accumulations and making it difficult to develop the reservoirs. Based on cores, thin sections, SEM, and fluid inclusions, this study examined sandstone composition and texture and diagenetic heterogeneity at the core scale. The aim was to understand the influence of variations in detrital composition and texture on diagenetic and reservoir quality evolution. The Ahe Formation sandstones are dominantly fine- to coarse-grained litharenites, with minor feldspathic litharenites. In fining-up sand beds, detrital grain size determines the degree of mechanical compaction and, consequently, the abundance of porosity through ductile grains and muddy matrix. Local complete calcite cementation is a noticeable exception to this general trend. Three sandstone petrofacies have been defined based on texture and framework composition, detrital matrix, diagenesis, and pore types: (1) ductile-lean sandstone, (2) ductile-rich sandstone, and (3) tightly calcite-cemented sandstone. Different petrofacies experienced contrasting diagenetic and porosity evolution pathways. Ductile-lean sandstones underwent lower degree of compaction relative to ductile-rich sandstones during the eodiagenesis stage, and extensive grain dissolution occurred. The petrofacies remained relatively porous and permeable before early oil arrival. With continued burial, the porosity and permeability in the sandstones were further reduced by cementation. The petrofacies still had moderate porosity and permeability and were substantially charged when late petroleum migrated into the reservoirs. Thus, ductile-lean sandstones constitute effective reservoir rocks in deep reservoirs. By translating petrofacies to signatures of well logs, the effective properties of the reservoir rocks can be forecasted at the well scale.

Reservoir Quality of the Miocene Formation Gas Deposits, Onshore Abu Dhabi

2021 ◽  
Author(s):  
Catherine Breislin ◽  
Laura Galluccio ◽  
Kate Al Tameemi ◽  
Riaz Khan ◽  
Atef Abdelaal
Keyword(s):  
Depositional Environment ◽  
Middle Miocene ◽  
Quality Analysis ◽  
Reservoir Quality ◽  
Carbonate Facies ◽  
Pore System ◽  
Thin Sections ◽  
Reservoir Architecture ◽  
Porosity And Permeability ◽  
Permeability Anisotropy

Abstract Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies. From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow. A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed. The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffles or barriers to vertical flow and create significant permeability anisotropy.

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.

PROSPECTIVITY AND EXPLORATION HISTORY OF THE BARROW SUB-BASIN, WESTERN AUSTRALIA

1997 ◽  
Vol 37 (1) ◽  
pp. 117 ◽  
Author(s):  
P.W. Baillie ◽  
E.P. Jacobson
Keyword(s):  
Lower Cretaceous ◽  
Source Rocks ◽  
Reservoir Quality ◽  
Liquid Hydrocarbons ◽  
Reservoir Rocks ◽  
Long Period ◽  
Porosity And Permeability ◽  
History Of ◽  
Hydrocarbon Reserves

The Carnarvon Basin is Australia's leading producer of both liquid hydrocarbons and gas. Most oil production to date has come from the Barrow Sub-basin. The success of the Sub-basin is due to a fortuitous combination of good Mesozoic source rocks which have been generating over a long period of time, Lower Cretaceous reservoir rocks with excellent porosity and permeability, and a thick and effective regional seal.A feature of Barrow Sub-basin fields is that they generally produce far more petroleum than is initially estimated and booked, a result of the excellent reservoir quality of the principal producing reservoirs.Structural traps immediately below the regional seal (the 'top Barrow play') have been the most successful play to date. Analysis of 'new' and 'old' play concepts show that the Sub-basin has potential for significant additional hydrocarbon reserves.

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.

Geology and petroleum prospectivity of the Sea of Hebrides Basin and Minch Basin, offshore northwest Scotland

2021 ◽  
pp. petgeo2021-003
Author(s):  
Laura-Jane C. Fyfe ◽  
Nick Schofield ◽  
Simon Holford ◽  
Adrian Hartley ◽  
Adrian Heafford ◽  
...  
Keyword(s):  
Poor Quality ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Small Scale ◽  
Organic Carbon Content ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Porosity And Permeability ◽  
Atlantic Margin

The Sea of Hebrides Basin and Minch Basin are late Palaeozoic-Mesozoic rift basins located to the northwest of the Scottish mainland. The basins were the target of small-scale petroleum exploration from the late 1960s to the early 1990s, with a total of three wells drilled within the two basins between 1989 and 1991. Although no commercially viable petroleum discoveries were made, numerous petroleum shows were identified within both basins, including a gas show within the Upper Glen 1 well in Lower Jurassic limestones. Organic rich shales have been identified throughout the Jurassic succession within the Sea of Hebrides Basin, with one Middle Jurassic (Bajocian-Bathonian) shale exhibiting a Total Organic Carbon content of up to 15 wt%. The focus of this study is to review the historic petroleum exploration within these basins, and to evaluate whether the conclusions drawn in the early 1990s of a lack of prospectivity remains the case. This was undertaken by analysis of seismic reflection data, gravity and aeromagnetic data and sedimentological data, from both onshore and offshore wells, boreholes and previously published studies. The key findings from our study suggest that there is a low probability of commercially sized petroleum accumulations within either the Sea of Hebrides Basin or the Minch Basin. Ineffective source rocks, likely due to low maturities (due to lack of burial) and the fact that the encountered Jurassic and Permian-Triassic reservoirs are of poor quality (low porosity and permeability) has led to our interpretation of future exploration being high risk, with any potential accumulations being small in size. While petroleum accumulations are unlikely within the basin, applying the knowledge obtained from the study could provide additional datasets and insight into petroleum exploration on other northeast Atlantic margin basins, such as the Rockall Trough and the Faroe-Shetland Basin.

Regional study of controls on reservoir quality in the Triassic Skagerrak Formation of the Central North Sea

2017 ◽  
Vol 8 (1) ◽  
pp. 125-146 ◽  
Author(s):  
M. Akpokodje ◽  
A. Melvin ◽  
J. Churchill ◽  
S. Burns ◽  
J. Morris ◽  
...  
Keyword(s):  
North Sea ◽  
Clay Content ◽  
Reservoir Quality ◽  
Primary Control ◽  
Regional Study ◽  
Thin Sections ◽  
Porosity Evolution ◽  
Heterogeneous Reservoirs ◽  
Low Degree ◽  
Central North Sea

AbstractAn improved understanding of the controls on reservoir quality is key to ongoing and future exploration of the Central North Sea Triassic play. This paper presents a regional integrated study of 50 000 ft of wireline log data, 10 000 ft of core, 4431 routine core analyses measurements and 377 thin sections from 86 cored wells.Triassic Skagerrak Formation sandstones represent thin-bedded heterogeneous reservoirs deposited in a dryland fluvial–lacustrine setting. Fluvial-channel facies are typically fine–medium grained and characterized by a low clay content, whilst lake-margin terminal splay facies are finer grained, more argillaceous and micaceous. Lacustrine intervals are mud-dominated. Primary depositional textures retain a primary control on porosity evolution through burial. Optimal reservoir quality occurs in aerially and stratigraphically restricted fluvial-channel tracts on the Drake, Greater Marnock, Puffin and Gannet terraces, and the J-Ridge area. These primary textural and compositional controls are overprinted by mechanical compaction, the development of early overpressure and diagenesis. Anomalously high porosities are retained at depth in fluvial sandstones that have a low degree of compaction and cementation, including chlorite. Forward modelling of reservoir quality using Touchstone™ software has been validated using well UK 30/8-3 where reservoir depths are >16 000 ft TVDSS (true vertical depth subsea).

scholarly journals Impact of Diagenesis on the Reservoir Properties of the Cretaceous Sandstones in the Southern Bredasdorp Basin, Offshore South Africa

Minerals ◽  
2020 ◽  
Vol 10 (9) ◽  
pp. 757
Author(s):  
Temitope Love Baiyegunhi ◽  
Kuiwu Liu ◽  
Oswald Gwavava ◽  
Christopher Baiyegunhi
Keyword(s):  
Oil And Gas ◽  
Gas Production ◽  
Reservoir Quality ◽  
Reservoir Properties ◽  
Oil And Gas Production ◽  
Thin Sections ◽  
Hydrocarbon Reservoir ◽  
Porosity And Permeability ◽  
The Impact

The Cretaceous sandstone in the Bredasdorp Basin is an essential potential hydrocarbon reservoir. In spite of its importance as a reservoir, the impact of diagenesis on the reservoir quality of the sandstones is almost unknown. This study is undertaken to investigate the impact of digenesis on reservoir quality as it pertains to oil and gas production in the basin. The diagenetic characterization of the reservoir is based on XRF, XRD SEM + EDX, and petrographic studies of 106 thin sections of sandstones from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 in the basin. The main diagenetic processes that have affected the reservoir quality of the sandstones are cementation by authigenic clay, carbonate and silica, growth of authigenic glauconite, dissolution of minerals and load compaction. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed up by the development of partial pore-lining and pore-filling clay cements, particularly illite. This clay acts as pore choking cement, which reduces porosity and permeability of the reservoir rocks. The scattered plots of porosity and permeability versus cement + clays show good inverse correlations, suggesting that the reservoir quality is mainly controlled by cementation and authigenic clays.

scholarly journals Diagenesis Processes Impact on Reservoir Quality in Carbonate Yamama Formation /Faihaa Oil Field

2020 ◽  
pp. 92-102
Author(s):  
Mohammed A. Ahmed ◽  
Madhat E. Nasser ◽  
Sameer N. AL Jawad
Keyword(s):  
Oil Field ◽  
Reservoir Quality ◽  
Genetic Classification ◽  
Thin Sections ◽  
Positive Effects ◽  
Diagenetic Processes ◽  
Porosity And Permeability ◽  
Cretaceous Period ◽  
The Impact

The Yamama Formation is a significant reservoir in the southern part of Iraq. This formation consists of limestone deposited throughout the Lower Cretaceous period within main retrogressive depositional series. This study aims to identify the impact of the diagenesis processes on the reservoir’s characteristics (porosity and permeability). Diagenesis processes’ analysis and the identification of Yamama Formation depended on the examination of more than 250 thin sections of the core samples from two wells that were used to determine different diagenetic environments and processes. The three identified diagenetic environments that affected Yamama reservoir were the marine, meteoric and burial environments. Eight diagenetic processes were recognized in Yamama Formation and showed positive and destructive effects on the reservoir quality; Dissolution and fracture had highly positive effects through creating and improving porosity and permeability that led to improving reservoir quality. Cementation and compaction had destructive effects, through reducing porosity and permeability, that led to reducing reservoir quality. Other processes such micritization, dolomitization, bioturbation and neomorphism did not have strong effects on reservoir quality. Based on genetic classification of porosity, most of porosity within Yamama Formation in this field was formed by diagenesis processes, implying that Yamama reservoir is a type of diagenetic reservoir.

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.

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