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Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks
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Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks

A special issue of Minerals (ISSN 2075-163X). This special issue belongs to the section "Clays and Engineered Mineral Materials".

Deadline for manuscript submissions: closed (30 November 2022) | Viewed by 21881

Special Issue Editors

Dr. Yi Fang

E-Mail Website
Guest Editor
Department of Geology and Geological Engineering, South Dakota School of Mines and Technology, Rapid City, SD 57701, USA
Interests: geomechanics and geofluids with applications for geo-energy and geo-resources (geothermal, unconventional hydrocarbon, and subsurface CO2 storage)
Dr. Brandon Schwartz

E-Mail Website
Guest Editor
Department of Energy and Mineral Engineering, EMS Energy Institute and G3 Center, The Pennsylvania State University, University Park, PA 16802, USA
Interests: experimental geomechanics; dynamic rock physics modeling; carbon sequestration; unconventional reservoirs
Special Issues, Collections and Topics in MDPI journals
Dr. Yong Li

E-Mail Website
Guest Editor
College of Geosciences and Surveying Engineering, China University of Mining and Technology (Beijing), Beijing, China
Interests: coal and coalbed methane; unconventional natural gas/oil resources; sedimentology
Special Issues, Collections and Topics in MDPI journals
Dr. Zhuang Sun

E-Mail Website
Guest Editor
Dassault Systèmes, 343 Sansome St, San Francisco, CA 94104-5607, USA
Interests: micromechanics; reservoir geomechanics; CO2 geological storage
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Clays and clay-based materials serve as reservoirs and caprocks for energy resources, storage and waste stream sequestration. The mineralogical, petrophysical and geomechanical characteristics are the information required for understanding unconventional origins, accumulation and evolution in different geological settings. This information also provides a foundation for the accurate modeling of subsurface energy engineering applications. The purpose of this Special Issue is to provide a cutting-edge insight to the multiscale mineralogical, petrophysical and geomechanical properties of shales or mudrocks, during coupled thermal, hydrologic, mechanical, chemical or biological processes in natural or anthrogenic activities.

We seek original research that explores the storage potential and evolution of material properties of shale or mudrocks during hydrogen injection, energy-waste containment and sequestration, gas hydrate formation, and geothermal infiltration. Submitted studies are expected to highlight the potential of shale and other clay-based materials to store and transport these fluids under in situ or in-house laboratory conditions. Work that explores the role of mineral distribution within shales in determining material response to CO2, H2, and other fluids of interest are encouraged.

Dr. Yi Fang
Dr. Brandon Schwartz
Dr. Yong Li
Dr. Zhuang Sun
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Minerals is an international peer-reviewed open access monthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2400 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

 

Keywords

  • reservoir characterization
  • caprock integrity
  • mineralogical control
  • petrophysical properties
  • hydromechanical coupling
  • shale gas
  • gas hydrate
  • hydrogen storage
  • CO2 sequestration

Published Papers (12 papers)

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Research

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12 pages, 2433 KiB  
Article
A New Approach to Predicting Vertical Permeability for Carbonate Rocks in the Southern Mesopotamian Basin
by Emad A. Al-Khdheeawi, Raed H. Allawi, Wisam I. Al-Rubaye and Stefan Iglauer
Minerals 2023, 13(12), 1519; https://0-doi-org.brum.beds.ac.uk/10.3390/min13121519 - 04 Dec 2023
Viewed by 1415
Abstract
Reservoir performance depends on many factors, and the most important one is permeability anisotropy. In addition, with high heterogeneity, it is essential to find unique relationships to predict permeability. Therefore, this study aims to predict vertical permeability based on horizontal permeability and porosity [...] Read more.
Reservoir performance depends on many factors, and the most important one is permeability anisotropy. In addition, with high heterogeneity, it is essential to find unique relationships to predict permeability. Therefore, this study aims to predict vertical permeability based on horizontal permeability and porosity and to find new equations for carbonate reservoirs. This work relied on the 398 measured points of cores data collected from several wells in carbonate reservoirs. A new correlation for predicting vertical permeability for the whole data (369 samples) as a function of horizontal permeability and porosity has been developed. The results indicate that this new correlation can estimate the vertical permeability with correlation coefficients (RSQ) of 0.853. Then, the used data were divided into four groups depending on the Kv/Kh values: less than 0.1, 1–0.1, 1–10, and more than 10, and a new correlation for permeability prediction for each group has been developed with good RSQ values of 0.751, 0.947, 0.963, and 0.826, respectively. The previous studies lack the correlations to predict vertical permeability in carbonate reservoirs, so this study can be considered as a reference for similar cases. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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12 pages, 6566 KiB  
Article
Fracture Identification Using Conventional Logs in Ultra-Low Permeability Sandstone Reservoirs: A Case Study of the Chang 6 Member of the Ordos Basin, China
by Shanbin He, Kun Meng, Ce Wang, Yingbo Chen, Hao Zhao, Haoyuan Wang and Hongyan Yu
Minerals 2023, 13(2), 297; https://0-doi-org.brum.beds.ac.uk/10.3390/min13020297 - 20 Feb 2023
Cited by 1 | Viewed by 1372
Abstract
The identification of reservoir fractures is essential as it is an important factor in the design of a field development plan, which in turn affects the efficiency of hydrocarbon production. Water flooding and water channeling are serious due to the lack of objective [...] Read more.
The identification of reservoir fractures is essential as it is an important factor in the design of a field development plan, which in turn affects the efficiency of hydrocarbon production. Water flooding and water channeling are serious due to the lack of objective understanding of the fracture development pattern in the tight oil reservoirs in the Triassic Change 6 member of Y well area, Ordos Basin, China. In this paper, we observed 104.6 m cores from 20 wells with a number of 150 fractures and an outcrop profile, then analyzed the main controlling factors for core fracture development, and finally established a fracture prediction method using conventional logging data. The results indicate that high-angle fractures accounted for 73.20%, fracture orientations were nearly east–west, fracture spacing between 0–10 cm accounted for 80.51%, fracture openings between 0–0.13 mm accounted for 89.27%, fracture down-cutting depths between 0–20 cm accounted for 80%, and 80.81% was not filled. In addition, we found that thin beds and fine sandstones are prone to develop fractures; Finally, our modified curve rate method was an effective method for fracture prediction. We conclude that fractures have the characteristics of high angle, small spacing, small opening, small down-cutting depth, and less filling. The modified curve change rate method is suitable for fracture prediction in tight sandstone reservoirs in the Triassic Change 6 member of the Y well area, Ordos Basin, China. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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22 pages, 7735 KiB  
Article
Depositional and Diagenetic Controls on Reservoir Quality of Neogene Surma Group from Srikail Gas Field, Bengal Basin, Bangladesh
by Maimuna Akter, M. Julleh Jalalur Rahman, Ming Ma, Delwar Hossain and Farida Khanam
Minerals 2023, 13(2), 283; https://0-doi-org.brum.beds.ac.uk/10.3390/min13020283 - 17 Feb 2023
Viewed by 1860
Abstract
The development of an effective and profitable exploration and production depends heavily on the quality of the reservoir. The primary goal of this study was to evaluate the reservoir quality of the Neogene Surma Group at the Srikail Gas Field, which is situated [...] Read more.
The development of an effective and profitable exploration and production depends heavily on the quality of the reservoir. The primary goal of this study was to evaluate the reservoir quality of the Neogene Surma Group at the Srikail Gas Field, which is situated in the western part of the eastern folded belt of the Bengal Basin, Bangladesh. Wire-line logs, core analysis, petrography, X-Ray diffraction (XRD) and a scanning electron microscope (SEM) were used to understand the depositional and diagenetic controls of the quality of the reservoir. The Surma Group of the Srikail Gas Field was deposited in a delta system with a dominant influence of tide. The subarkosic to sublitharenitic Neogene Surma Group sandstones have primary porosities ranging from 0% to 25.8%, with an average of 21.5%, and the secondary porosity is approximately 7%. The range of log porosity ranges from 15% to 22.2%, while log permeability and core permeability vary from 3.01 to 54.09 mD and 0.1 to 76 mD, respectively. The primary porosity had been destroyed mainly by mechanical and ductile grain compaction. Most of the clay minerals (illite/illite-smectite, chlorite and kaolinite) in sandstone occur as grain coatings, grain lining (rim) and a few occur as pore-filling. This study reveals that the reservoir quality is predominantly controlled by the depositional environment (sediment texture and facies, ductile grain supply, clay content), and diagenetic process (mainly mechanical and ductile grain compaction followed by clay cement). The information gathered from this research will be useful for future petroleum production and for enhancing predictability in order to find new prospects. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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13 pages, 4742 KiB  
Article
Molecular Simulation Study on Methane Adsorption in Amorphous Shale Structure
by Aminah Qayyimah Mohd Aji, Dzeti Farhah Mohshim, Belladonna Maulianda and Khaled Abdalla El-Raeis
Minerals 2023, 13(2), 214; https://0-doi-org.brum.beds.ac.uk/10.3390/min13020214 - 01 Feb 2023
Cited by 3 | Viewed by 1663
Abstract
Gas adsorption in the porous shale matrix is critical for gas-in-place (GIP) evaluation and exploration. Adsorption investigations benefit significantly from the use of molecular simulation. However, modelling adsorption in a realistic shale topology remains a constraint, and there is a need to study [...] Read more.
Gas adsorption in the porous shale matrix is critical for gas-in-place (GIP) evaluation and exploration. Adsorption investigations benefit significantly from the use of molecular simulation. However, modelling adsorption in a realistic shale topology remains a constraint, and there is a need to study the adsorption behaviour using molecular models containing both organic and inorganic nanopores. Most simulations use a single component, either kerogen (organic composition) and quartz or clay (inorganic composition), to represent the shale surface. In this work, the molecular dynamic (MD) and grand conical Monte Carlo (GCMC) simulations were utilised to provide insight into methane adsorption behaviour. Amorphous shale structures composed of kerogen and quartz were constructed. The kerogen content was varied to replicate the shale with 2 wt.% and 5 wt.% Total Organic Carbon (TOC) content with 5 nm pore size. The simulated densities of the shale structures showed consistent values with actual shale from the Montney, Antrim, and Eagle Ford formations, with 2.52 g/cm3 and 2.44 g/cm3, respectively. The Average Error Analysis (ARE) was used to assess the applicability of the proposed amorphous shale model to replicate the laboratory adsorption isotherm measurements of actual shale. The ARE function showed that the amorphous shale shows good agreement with experimental measurements of all Barnett shale samples with an average of 5.0% error and slightly higher for the Haynesville samples with 8.0% error. The differences between the experimental adsorption measurement and simulation resulted from the amorphous packing, and actual shales have more minerals than the simulated model. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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16 pages, 8466 KiB  
Article
Asphaltene Behavior during Thermal Recovery: A Molecular Study Based on Realistic Structures
by Saad Alafnan
Minerals 2022, 12(10), 1315; https://0-doi-org.brum.beds.ac.uk/10.3390/min12101315 - 18 Oct 2022
Cited by 1 | Viewed by 1318
Abstract
Asphaltene precipitation and deposition can occur at both the surface and subsurface levels, leading to the formation of organic-based scales. Asphaltene precipitation can also lead to changes in petrophysical properties such as wettability, which affects the ultimate recovery. Asphaltene precipitation is linked to [...] Read more.
Asphaltene precipitation and deposition can occur at both the surface and subsurface levels, leading to the formation of organic-based scales. Asphaltene precipitation can also lead to changes in petrophysical properties such as wettability, which affects the ultimate recovery. Asphaltene precipitation is linked to changes in fluid composition driven by pressure drawdown and temperature variation across the reservoir. Thus, asphaltene deposition can adversely influence the ultimate recovery. Thermal recovery methods are invoked to mitigate the adverse effects of asphaltene precipitation. The behavior of asphaltene under thermal recovery along with the link between the asphaltene molecular structure and its response to the increase in temperature during thermal recovery are not fully understood. In this paper, realistic asphaltene structures based on actual crude samples were recreated on a computational platform, and several characteristics of the asphaltene structures (density, viscosity, and interfacial tension) were evaluated during the heating process. The density of asphaltene was correlated with the percentage of aromatic carbon in its structure. The viscosity and interfacial tension decreased substantially as the temperature increased. The IFT reduced by approximately 30 mN/m as the temperature was increased from 300 K to 450 K. Moreover, the mechanical stability of asphaltene was found to be highly influenced by heating. The findings provide nanoscale insights into the behavior of asphaltene during thermal recovery, which can be used to improve the design of thermal recovery processes. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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17 pages, 6572 KiB  
Article
The Impact of Detrital Minerals on Reservoir Flow Zones in the Northeastern Bredasdorp Basin, South Africa, Using Core Data
by Mimonitu Opuwari, Moses Okon Ubong, Simamkele Jamjam and Moses Magoba
Minerals 2022, 12(8), 1009; https://0-doi-org.brum.beds.ac.uk/10.3390/min12081009 - 12 Aug 2022
Cited by 2 | Viewed by 1578
Abstract
The present study uses core data to group reservoirs of a gas field in the Bredasdorp Basin offshore South Africa into flow zones. One hundred and sixty-eight core porosity and permeability data were used to establish reservoir zones from the flow zone indicator [...] Read more.
The present study uses core data to group reservoirs of a gas field in the Bredasdorp Basin offshore South Africa into flow zones. One hundred and sixty-eight core porosity and permeability data were used to establish reservoir zones from the flow zone indicator (FZI) and Winland’s methods. Storage and flow capacities were determined from the stratigraphy-modified Lorenz plot (SMLP) method. The effects of the mineralogy on the flow zones were established from mineralogy composition analyses using quantitative X-ray diffraction (XRD) and Scanning Electron Microscopy (SEM). Results reveal five flow zones grouped as high, moderate, low, very low, and tight reservoir rocks. The high flow zone is the best reservoir quality rock and has porosity and permeability values ranging from 12 to 20% and 100 to 1000 mD. The high and moderate zones contribute more than 60% of each well’s flow capacities. The moderate and low flow zone extends laterally to all the wells. The tight flow zone is an impervious rock and has the lowest rock quality with porosity and permeability values less than 8% and 1 mD, respectively. This zone contributes less than 1% to flow capacity. The impact of minerals on flow zones is evident in plagioclase and muscovite content increases. An accompanied decrease in quartz content is observed, which implies that low plagioclase content ≤4% and muscovite content of ≤1% corresponds to the low, moderate, and high flow zones, while plagioclase content of ≥4% and muscovite content of ≥1% belong to the tight flow zone. Consequently, the quantity of plagioclase and muscovite can be used as a proxy to identify better quality reservoir rocks. The diagenetic process that reduces the rock quality can be attributed to quartz overgrowth and the accumulation of mica flakes in the pore spaces. In contrast, the fracture in the high flow zone is the reservoir quality enhancing process. The flow zones are generally controlled by a combination of facies and diagenetic factors. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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14 pages, 5029 KiB  
Article
Verification and Application of Sequence Stratigraphy to Reservoir Characterization of Horn River Basin, Canada
by Juhwan Woo, Jiyoung Choi, Seok Hoon Yoon and Chul Woo Rhee
Minerals 2022, 12(6), 776; https://0-doi-org.brum.beds.ac.uk/10.3390/min12060776 - 18 Jun 2022
Cited by 1 | Viewed by 2101
Abstract
Shale reservoirs, the most important unconventional resource, are difficult to characterize. Shale formations require detailed interpretation of geological, petrophysical, and geochemical analyses, and an integration of these disciplines. In terms of geological interpretation, the commonly used sequence stratigraphy analysis includes a lithofacies analysis. [...] Read more.
Shale reservoirs, the most important unconventional resource, are difficult to characterize. Shale formations require detailed interpretation of geological, petrophysical, and geochemical analyses, and an integration of these disciplines. In terms of geological interpretation, the commonly used sequence stratigraphy analysis includes a lithofacies analysis. The application of sequence stratigraphy to shales facilitates the ability to relate between lithofacies and mineral composition, petrophysical parameters, and kerogen contents, which are affected by depositional setting. The classification of lithofacies is indispensable for reservoir quality prediction. In this study, porosity, permeability, and TOC content largely depend on lithofacies, and their correlation coefficient is relatively high. The sequence stratigraphic interpretation shows that organic carbon content usually increases within the maximum flooding surfaces and decreases stepwise. However, the relationship between total organic carbon contents and systems tract is less direct and redox dependent. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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18 pages, 4812 KiB  
Article
Experimental Setup for Evaluating Rock Volume Alteration and Its Application for Studying Shale Rock Swelling in Various Fluids
by Timur I. Yunusov, Alexey V. Smirnov, Elena D. Mukhina, Dmitriy I. Potapenko, Dinar F. Bukharov, Anatoly A. Baluev and Alexey N. Cheremisin
Minerals 2022, 12(6), 714; https://0-doi-org.brum.beds.ac.uk/10.3390/min12060714 - 03 Jun 2022
Cited by 1 | Viewed by 1497
Abstract
Rock swelling and rock disintegration in the presence of drilling, stimulation and completion fluids are considered to be the main reasons for operational and production problems for wells in clay-rich formations. The impact of these fluids on rock properties shall be established for [...] Read more.
Rock swelling and rock disintegration in the presence of drilling, stimulation and completion fluids are considered to be the main reasons for operational and production problems for wells in clay-rich formations. The impact of these fluids on rock properties shall be established for the effective treatment design. This paper describes the development of the experimental setup for studying rock swelling in reservoir conditions and the application of this setup for the evaluation of swelling mechanisms of shale rock samples. Swelling quantification was performed using measuring piston displacement that was caused by rock swelling in a piston accumulator during pressure maintenance. We studied the interaction of the disintegrated rock samples with water-based and hydrocarbon-based fluids and supercritical CO2. It was found that alkaline water solution in reservoir conditions causes swelling of the used rock samples in the amount of 1–3% vol. with a direct correlation between the rock swelling magnitude and the total clay content. The change in the rock volume in the presence of the used hydrocarbon-based fluid depends on the content of organic matter, its distribution in the rock, and the clay content. The observed swelling degree in the hydrocarbon fluid and CO2 was significantly lower (0–0.5% vol.) than in water. The proposed methodology and obtained results can further be used for the optimization of various operations in clay-rich formations. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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18 pages, 5259 KiB  
Article
Influence of Particle Size on the Low-Temperature Nitrogen Adsorption of Deep Shale in Southern Sichuan, China
by Hongming Zhan, Xizhe Li, Zhiming Hu, Xianggang Duan, Wei Guo and Yalong Li
Minerals 2022, 12(3), 302; https://0-doi-org.brum.beds.ac.uk/10.3390/min12030302 - 27 Feb 2022
Cited by 7 | Viewed by 2067
Abstract
Pore characteristics are one of the most important elements in the study of shale reservoir properties and are a key parameter for the evaluation of the potential of shale oil and gas resources. Low-temperature nitrogen adsorption is a common laboratory method that is [...] Read more.
Pore characteristics are one of the most important elements in the study of shale reservoir properties and are a key parameter for the evaluation of the potential of shale oil and gas resources. Low-temperature nitrogen adsorption is a common laboratory method that is used to characterize the pore structure of shale. However, the effect of shale’s particle size on the experimental results of the nitrogen adsorption of deep shale samples is still unclear. In this paper, using deep shale samples of different mesh sizes from the Luzhou Block as an example, we studied the effect of particle size on the pore structure of deep shale, as characterized by nitrogen adsorption experiments. The results showed that the pore volume of deep shale is mainly distributed in the mesoporous range, with a pore size ranging from 2 to 20 nm. The pore volume, as measured by nitrogen adsorption, increases slowly as the particle size decreases and then it increases rapidly. The particle size of shale has no obvious effect on the measurement of the specific surface area. The fractal dimension of deep shale gradually increases as the particle size of the shale samples increases and the smaller the particle size, the higher the correlation coefficient, R2, of the fractal dimension fitting. In this paper, different recommended sizes are given for selecting suitable particle sizes in nitrogen adsorption experiments on deep shale with different structural parameters, which will increase the accuracy of the study of the pore structure of deep shale. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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18 pages, 11691 KiB  
Article
Mineral Composition of Prospective Section of Wufeng-Longmaxi Shale in Luzhou Shale Play, Sichuan Basin
by Hongzhi Yang, Xuewen Shi, Chao Luo, Wei Wu, Yi Li, Yifan He, Kesu Zhong and Jianguo Wu
Minerals 2022, 12(1), 20; https://0-doi-org.brum.beds.ac.uk/10.3390/min12010020 - 23 Dec 2021
Cited by 5 | Viewed by 2414
Abstract
Currently, Luzhou in the Sichuan Basin is a focal point for shale-gas exploration and development in China. However, a lack of detailed research on the mineral composition of the Wufeng Formation-Longmaxi Formation (WF-LF) shale is hindering the extraction of deep-buried shale gas in [...] Read more.
Currently, Luzhou in the Sichuan Basin is a focal point for shale-gas exploration and development in China. However, a lack of detailed research on the mineral composition of the Wufeng Formation-Longmaxi Formation (WF-LF) shale is hindering the extraction of deep-buried shale gas in the Luzhou shale play. Herein, a field emission scanning electron microscope (FESEM) equipped with the Advanced Mineral Identification and Characterization System (AMICS) software was employed to analyze the mineral composition of the WF-LF shale from six wells in Luzhou. Quartz was the dominant mineral type, (16.9–87.21%, average 51.33%), followed by illite, calcite, dolomite, and pyrite. Our study revealed that (1) quartz content showed a moderate positive correlation with the total organic carbon (TOC) content, indicating that the quartz found in the shale is mostly of biological origin; and (2) the sum content of siliceous minerals and carbonaceous minerals was moderately positively correlated with the brittleness index (BRIT) in well SS1H2-7 and in the well group of RS8 and RS5, indicating that the siliceous minerals and carbonaceous minerals had an active effect on reservoir compressibility. Finally, according to the mineralogical features of each sublayer, we identified four types of reservoirs to determine their scope for exploration. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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14 pages, 6568 KiB  
Article
Tight Sandstone Reservoir Formation Mechanism of Upper Paleozoic Buried Hills in the Huanghua Depression, Bohai Bay Basin, Eastern China
by Lihong Zhou, Yong Li, Fengming Jin, Lixin Fu, Xiugang Pu, Lou Da, Hongjun Li, Haitao Liu and Weikai Xu
Minerals 2021, 11(12), 1368; https://0-doi-org.brum.beds.ac.uk/10.3390/min11121368 - 03 Dec 2021
Cited by 4 | Viewed by 2259
Abstract
Carboniferous-Permian petroleum resources in the Huanghua Depression of the Bohai Bay Basin, a super petroleum basin, are important exploration successor targets. The reservoir sedimentary environment of coal measures in the Upper Paleozoic buried hills is variable, and the structural evolution process is complicated, [...] Read more.
Carboniferous-Permian petroleum resources in the Huanghua Depression of the Bohai Bay Basin, a super petroleum basin, are important exploration successor targets. The reservoir sedimentary environment of coal measures in the Upper Paleozoic buried hills is variable, and the structural evolution process is complicated, which restricts the optimization of targeting sections. Using the analysis and testing results of logging, thin section, porosity, mercury injection, hydrochemistry, and basin simulation, this study revealed the formation mechanism differences of tight sandstones in the Upper Paleozoic period in different buried hills. The results show that the sandstones are mainly feldspathic sandstone, lithic arkose, feldspathic lithic sandstone, and feldspathic lithic quartz sandstone. The quartz content varies between 25% and 70%, averaging 41%. Feldspar and debris are generally high, averaging 31% and 28%, respectively. Secondary dissolution pores are the main reservoir spaces, with 45% of the tested samples showing porosity of 5–10%, and 15% being lower than 5%. The pore radium is generally lower than 100 nm, and the sandstones are determined as small pore with fine throat and medium pore with fine throat sandstones by mercury saturation results. Frequent changing sedimentary environments and complex diagenetic transformation processes both contribute to the reservoir property differences. The former determines the original pore space, and the latter determines whether they can be used as effective reservoirs by controlling the diagenetic sequences. Combining tectonic movement background and different fluid history, the different formation mechanisms of high-porosity reservoirs are recognized, which are atmospheric leaching dominated (Koucun buried hills), atmospheric water and organic acid co-controlled (Wangguantun and Wumaying buried hills), and organic acid dominated (Nandagang buried hills) influences. The results can be beneficial for tight gas exploration and development in coal measures inside clastic buried hills in the Bohai Bay Basin. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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Review

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23 pages, 2938 KiB  
Review
Application of Minerals for the Characterization of Geothermal Reservoirs and Cap Rock in Intracontinental Extensional Basins and Volcanic Islands in the Context of Subduction
by Béatrice A. Ledésert
Minerals 2024, 14(3), 263; https://0-doi-org.brum.beds.ac.uk/10.3390/min14030263 - 29 Feb 2024
Viewed by 836
Abstract
Whether from the near-surface or at great depths, geothermal energy aims to harness the heat of the Earth to produce energy. Herein, emphasis is put on geothermal reservoirs and their cap rock in crystalline rocks, in particular, the basements of sedimentary basins and [...] Read more.
Whether from the near-surface or at great depths, geothermal energy aims to harness the heat of the Earth to produce energy. Herein, emphasis is put on geothermal reservoirs and their cap rock in crystalline rocks, in particular, the basements of sedimentary basins and volcanic islands in the context of subduction. This study is based on a case study of three examples from around the world. The aim of this paper is to show how the study of newly formed minerals can help the exploration of geothermal reservoirs. The key parameters to define are the temperature (maximum temperature reached formerly), fluid pathways, and the duration of geothermal events. To define these parameters, numerous methods are used, including optical and electronic microscopy, X-ray diffraction, microthermometry on fluid inclusions, chlorite geothermometry, and geochemistry analysis, including that of isotopes. The key minerals that are studied herein are phyllosilicates and, in particular, clay minerals, quartz, and carbonates. They are formed because of hydrothermal alterations in fracture networks. These minerals can have temperatures of up to 300 °C (and they can cool down to 50 °C), and sometimes, they allow for one to estimate the cooling rate (e.g., 150 °C/200 ka). The duration of a hydrothermal event (e.g., at least 63 Ma or 650 ka, depending on the site) can also be established based on phyllosilicates. Full article
(This article belongs to the Special Issue Mineralogical, Petrophysical and Hydromechanical Properties of Reservoirs and Caprocks)
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