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Upper Permian Longtan Formation transitional shale has become an important exploration layer, but the Longtan Formation shale (LFS) has a complex mineralogical composition, which affects the subsequent diagenesis and diagenetic evolution, and restricts the subsequent geologic exploration of shale gas. In this article, the observation of drilling cores, argon ion polishing-scanning electron microscope, Vitrinite reflectance, and X-ray diffractometer were used to analyze the type and characteristics of diagenesis of the LFS and clarify the stage of diagenetic evolution. The results show that the main diagenesis in the LFS is compaction, cementation, thermal maturation of organic matter (OM), dissolution, and transform of clay minerals. Among them, OM hydrocarbon generation, clay mineral transformation, and dissolution are pore-enhancing diagenetic events. Compaction and cementation are pore-reducing diagenetic events. The transitional and marine shales have similar characteristics of diagenesis, but there are big variations in the diagenesis of OM hydrocarbon, authigenic quartz, and siderite. The complex depositional environments of the marine-continental transition environment have resulted in a variety of rock types, which in turn influenced the diagenesis types and diagenetic evolution process. Compared with the transitional shales of the Shanxi and Taiyuan formations in the South China North Basin, the LFS are characterized by high clay content, low quartz content, complex mineral compositions, and a higher degree of thermal evolution.

Slickwater fracturing fluids are widely used in the development of unconventional oil and gas resources due to the advantages of low cost, low formation damage and high drag reduction performance. However, their performance is severely affected at high temperatures. Drag reducing agent is the key to determine the drag reducing performance of slickwater. In this work, in order to further improve the temperature resistance of slickwater, a temperature-resistant polymeric drag reducing agent (PDRA) was synthesized and used as the basis for preparing the temperature-resistant slickwater. The slickwater system was prepared with the compositions of 0.2 wt% PDRA, 0.05 wt% drainage aid nonylphenol polyoxyethylene ether phosphate (NPEP) and 0.5 wt% anti-expansion agent polyepichlorohydrindimethylamine (PDM). The drag reduction ability, rheology properties, temperature and shear resistance ability, and core damage property of slickwater were systematically studied and evaluated. In contrast to on-site drag reducing agent (DRA) and HPAM, the temperature-resistant slickwater demonstrates enhanced drag reduction efficacy at 90 °C, exhibiting superior temperature and shear resistance ability. Notably, the drag reduction retention rate for the slickwater achieved an impressive 90.52% after a 30-min shearing period. Additionally, the core damage is only 5.53%.We expect that this study can broaden the application of slickwater in high-temperature reservoirs and provide a theoretical basis for field applications. [ABSTRACT FROM AUTHOR]

The first Geo-Energy Frontier Forum with the theme of "opportunities and challenges for geo-energy exploration and development" was successfully held in Wuhan, recently. The forum included 32 sessions, mainly focused on four directions: geo-energy development and reserve, petroleum geophysical exploration, oil and gas geology, and field development engineering. This paper summarizes the key findings in the 22nd session titled "Reservoir stimulation for unconventional oil and gas resources". A total of 17 experts and scholars participated in the presentations, covering a wide range of topics in unconventional oil and gas resources development. This research collectively highlighted the significance of reservoir stimulation techniques in unconventional oil and gas resource development, including research progress in fracture network modeling techniques, fluid pressure, rock mechanics, fracture propagation, and proppant migration in hydraulic fracturing. [ABSTRACT FROM AUTHOR]

For several decades the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Upper Jurassic to Lower Cretaceous Kimmeridge Clay Formation (KCF). In this study, we have combined the analysis of total organic carbon/pyrolysis and vitrinite reflectance geochemical data from KCF samples with 1D basin modelling to investigate the potential for shale oil and gas plays in the Outer Moray Firth region. The results of geochemical evaluation show that most of the samples have very good to excellent hydrocarbon generation potential and contain predominantly oil-prone Type-II kerogen. A few samples show a significant oil saturation index above 100 mgHC/gTOC, which indicate a good potential for producible shale oil. The modelling results suggest that vitrinite reflectance values for the KCF vary mainly between 0.51 and 1.15%Ro, with kerogen transformation of up to 86 %. This is indicative of early-oil to late-oil/early-gas maturity window at present day, and within the range reported for proven shale oil plays. The KCF shows good oil saturation in most of the modelled well locations of up to 6.4 mg/g rock, indicating potentially producible shale oil. Predictions from modelling support the interpretations from geochemical data. [ABSTRACT FROM AUTHOR]

Previous studies have mainly focused on the source rocks of the 7th Member of Yanchang Formation (Chang 7 Member) in the Ordos Basin, with very few studies focusing on the extracts from the source rocks. These extracts have important guiding significance for studying the in situ conversion process of shale oil. Taking the shale source rock of the Chang 7 Member as an example, this paper selected the extract of shale source rock (i.e., retained oil), which has been less studied previously, as the sample to carry out the hydrocarbon-generating pyrolysis simulation experiment of a semi-open–semi-closed system. Seven groups of parallel simulation experiments were designed with a pressure of 20 MPa. The generated oil and gas were collected and quantified, and their geochemical characteristics were researched. In addition, the generated oil and gas were investigated from aspects of cumulative yield and net increased yield, and the chromatographic and mass spectral characteristics of the generated oil were also researched. Based on this, an inductive hydrocarbon generation model of retained oil in shale source rocks was established: slow hydrocarbon generation stage (300–320 °C), rapid hydrocarbon generation stage (320–360 °C), and residual oil pyrolysis stage (0.79%Ro–1.47%Ro). This study is of important significance to guide the research on the in situ conversion process of shale source rock. [ABSTRACT FROM AUTHOR]

For several decades the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Upper Jurassic to Lower Cretaceous Kimmeridge Clay Formation (KCF). In this study, we have combined the analysis of total organic carbon/pyrolysis and vitrinite reflectance geochemical data from KCF samples with 1D basin modelling to investigate the potential for shale oil and gas plays in the Outer Moray Firth region. The results of geochemical evaluation show that most of the samples have very good to excellent hydrocarbon generation potential and contain predominantly oil-prone Type-II kerogen. A few samples show a significant oil saturation index above 100 mgHC/gTOC, which indicate a good potential for producible shale oil. The modelling results suggest that vitrinite reflectance values for the KCF vary mainly between 0.51 and 1.15%Ro, with kerogen transformation of up to 86 %. This is indicative of early-oil to late-oil/early-gas maturity window at present day, and within the range reported for proven shale oil plays. The KCF shows good oil saturation in most of the modelled well locations of up to 6.4 mg/g rock, indicating potentially producible shale oil. Predictions from modelling support the interpretations from geochemical data.

Lithofacies and micropore characteristics of shale reservoir directly affect the exploration and development of natural gas. To determine the development potential of shales of the Longmaxi Formation in the Western Hunan‐Hubei Region, the lithofacies types and micropore structure characteristics of the Longmaxi Formation shales have been systematically studied in this paper, based on ordinary thin sections, argon ion polishing–scanning electron microscopy, physical property testing, x‐ray diffraction whole‐rock and clay mineral analysis, isothermal nitrogen, and carbon dioxide adsorptions. According to the principle of 'laminar structure + total organic carbon (TOC) + mineral composition of felsic, clay, and carbonate minerals', eight types of shale lithofacies were identified. The effective porosity of the Longmaxi shale ranges from 1.8% to 14.4%, with a peak range from 3% to 6%, while the permeability ranges from 0.001 to 1.27 mD, with an average of 0.106 mD. Combined with the isothermal adsorption experiments, the proportion of mesopores is the largest in the Longmaxi shale, followed by macropores and micropores. Moreover, the pore diameters of mesopores are concentrated between 3 and 10 nm, while those of micropores are concentrated between 0.4 and 0.9 nm. The pore volume of shale is most developed when the content of brittle felsic minerals is 50% ~ 75% and the content of clay minerals is 25% ~ 50%, and the TOC content is positively correlated with the pore volume and specific surface area. There are significant differences in the pore development characteristics of different lithofacies. The shale reservoir space analysis indicates that micropores are controlled by TOC content and clay minerals, while the macropores are controlled by depositional intergranular pores, TOC content, and felsic content, as well as diagenetic pyrite mould pores, microfractures pores, and intercrystalline pores. On the other hand, mesopores are related to a mix of depositional and diagenetic factors with dominant contribution of intergranular pores, intercrystalline pores, organic pores, and intergranular shrinkage fractures pores. It is found that the pore development of massive organic‐rich siliceous shale lithofacies has the best reservoir quality, including well‐connected intergranular pores, intercrystalline pores, organic pores, and shrinkage fractures. Therefore, the massive organic‐rich siliceous shale lithofacies is the dominant fine‐grained reservoir lithofacies in the studied area. Based on understating the pore characteristics of different lithofacies, this study can provide a scientific basis for the prediction of favourable sweet spots of shale gas reservoir in the Longmaxi Formation, western Hunan‐Hubei Region. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing plays a crucial role in the development of unconventional resources, and assessing fracture geometry is a fundamental aspect of hydraulic fracturing analysis. Among the various technologies for evaluating fracture geometry, the water percussion signal-based method has gained popularity due to its cost-effectiveness, convenience, and real-time capabilities. In this study, we present a methodology for analyzing fracture data that utilizes the water percussion effect. By leveraging the impact of fractures on water percussion pressure attenuation, we propose an inverse calculation approach to determine fracture geometry. Firstly, we introduce the RCI (Reservoir-Completion-Interaction) circuit model, which effectively addresses the bottom hole fracture boundary and simulates the variation of water percussion pressure in the wellbore. Secondly, the simulation results are utilized in an iterative process to determine the RCI values, which are then utilized for the inversion calculation of fracture geometry. Finally, we apply this method to a field case and compare the simulation results with microseismic monitoring data. A larger resistance (R) value indicates a smaller fracture volume, while the (C) value can be used to monitor any poorly performing stages of the fracturing simulation process. The (I) value primarily affects the parameter calculation of the fracture size, especially the fracture width. The results of the field application show that the accuracy rate exceeding 80%, validating the reliability of the model and providing a valuable reference for field fracturing data analysis.

Recent advancements in technologies to produce natural gas from shales at economic rates has revealed new horizons for hydrocarbon exploration and development worldwide. The importance of shale oil and gas has aroused worldwide interest after the great success of production in North America. In this study, different marine source rocks of Pakistan are evaluated for their shale gas potential using analogs selected from various North American shales for which data have been published. Pakistani formations reviewed are the Datta (shaly sandstone), Hangu (sandy shale), Patala (sandy shale), Ranikot (shaly sandstone), Sembar (sandy shale) and Lower Goru (shaly sandstone) formations, all of which are known source rocks in the Indus Basin. Available geological data of twenty-six wells (e.g., geological age, depositional environment, lithology and thickness), geochemical data (e.g., total organic carbon (TOC), vitrinite reflectance (Ro), rock pyrolysis analysis and maturity), petrophysical data (e.g., porosity and permeability) and dynamic elastic parameters estimated from logs (Young’s modulus and Poisson’s ratio) have been investigated. According to this study, the Pakistani shales are explicitly correlated with the most active shale gas plays of North America. The burial depths or geological position of the Pakistani shales are generally comparable to or slightly higher than the North American shales based on the available data. The thicknesses of the Pakistani (except for the Sembar shale) and North American shales fall in similar ranges. In terms of mineralogical composition, all of the Pakistani shales except the Ranikot and Hangu shales have quartz contents in the 40% to 50% range (approximately), which is similar to most of the North American shales. The high maximum TOC of the Hangu and Sembar shales (10%) is comparable to the New Albany, Antrim and Duvernay shales. The maximum TOC values for the Ranikot (3%), Lower Goru (1.5%) and Datta (2%) shales are lower than all North American shales. The TOC of Patal Shale (∼5%–10%) is comparable to Fayetteville and Eagle Ford shales. The geological and geochemical parameters of all the Pakistani shales reviewed in this work are promising regarding their shale gas prospects. However, geomechanical data are required before conclusions on these shales’ economic production can be made with confidence.

Introduction: Resource constraints in primary health care settings in South Africa give rise to challenges for occupational therapists. This study aimed to determine the physical activity resource needs (including objects used and space demands) of occupational therapists in the primary health care context of Gauteng, South Africa. Method: A qualitative, descriptive research design was used. The participants were occupational therapists working in primary health care settings in Gauteng. Convenience and snowball sampling were used. Data were collected through two online asynchronised focus groups, conducted over three days each. Thematic analysis was used to analyse the data. Findings: Findings included the resource constraints experienced by occupational therapists and how the occupational therapists' adaptability helped them overcome these constraints. Space, resources for basic and instrumental activities of daily living, assistive devices, Bobath plinths and recyclable and low-cost materials were identified as being particularly useful physical activity resource needs. Conclusion: Although limited physical activity resources were available in the settings, therapists' skills in adaptability proved useful in using unconventional resources instead. This study's results identify physical resources deemed as most useful to provide occupational therapy services in primary health care. Furthermore, the results provide information to the education faculty in order to adapt the undergraduate curriculum to better prepare occupational therapy students for practice in primary health care. Implications for practice • The findings can be communicated to management of primary health care facilities in order to procure or advocate for the procurement of resources deemed as essential in primary health care practice contexts. • Innovation, problem-solving and adaptability can be valuable characteristics used in professional reasoning that may enable occupational therapists to overcome physical resource barriers. • Faculty at tertiary educational institutions may utilise the findings in order to adapt curriculums to better prepare occupational therapists for work in the South African primary health care context. • Occupational therapy students should gain experience in developing and adapting activities using recyclable and reusable materials for diverse clients, including children and adults. [ABSTRACT FROM AUTHOR]

Experts have identified natural gas hydrates, which are found in the shallow seabed and beneath permafrost regions, as an energy source (mostly methane) that is greener than other petroleum fuel resources. With their worldwide distribution and abundance, gas hydrates have vast potential to become the next pillar of the energy industry. Although no entity has established methane extraction from hydrates at a commercial scale yet, extensive laboratory experiments have introduced several extraction strategies. Methods such as depressurization, thermal stimulation, and inhibitor injection are likely to disturb seabed integrity, which may result in catastrophic consequences. However, the CO2 replacement method is inferred to be preserving the seabed stability, offering an opportunity to reduce anthropogenic CO2 emissions safely. In this paper, we provide a comprehensive review of the progress of experimental work in developing methane-extraction methods for gas hydrate reservoirs. Depressurization combined with thermal stimulation can be proposed as a viable methane extraction method based on laboratory-scale experiments, however, a sustainable extraction method is yet to be developed to field-scale when both economic and environmental perspectives are considered. A handful of field production runs have delivered positive outcomes to establish the exploitability of natural hydrate reservoirs, but thorough investigations and scientific collaborations are needed to develop hydrate accumulations as a commercially viable energy source.

The rapid depletion of conventional hydrocarbons has shifted the industry's focus to other sources of energy which are uncommon. Unconventional opportunities are more important than the conventional opportunities, and they require high capital levels to be achieved. This analysis intends to fill a gap in the market with a modern and concise overview of Coal Bed Methane for students and newcomers to the business. This study discusses the various categories of coal rankings and the different generations of CBM. It covers the background of CBM industry along with its journey throughout these years. Considering India's increasing economic and population growth, innovative approaches to optimize sources of energy is an urgent need. As a result, India has been actively researching and improving its CBM capital through international tendering processes over all these years. CBM is an unconventional natural gas source and is currently being evaluated as a potential option for fulfilling India's increasing energy demands. Therefore, complete analysis of the Indian CBM Market has been conducted discussing various CBM extraction techniques. An evaluation of the impact of India's geography on CBM market has been performed. The study concludes with discussion of the future of CBM in India and throughout the world. [ABSTRACT FROM AUTHOR]

The Gulf of Suez in Egypt contains more than 80 conventional oil fields with reservoirs from Precambrian up to Quaternary age. To date, these fields have all been conventional resources. This abstract will take part of the Gulf of Suez sequence within the fields of Petrogulf Misr Company and present a work process for unconventional resource assessment of the Brown Limestone formation within one of these areas. The Brown Limestone formation is a Late Cretaceous Pre-rift mega sequence succession and plays an important role in the conventional system of Gulf of Suez, Brown Limestone formation is not only as one of the important source rocks, but also a fractured carbonate reservoir in multiple fields especially is the southern Geisum oil field. However, this formation is characterized by uncertainty due to the complexity of reservoir architecture, various lithologies, lateral facies variations, and heterogeneous reservoir quality. These reservoir challenges, in turn, affect the effectiveness of further exploitation of this reservoir along the Gulf of Suez Basin. In this work, we conduct an integrated study using multidisciplinary datasets and techniques to determine the precise structural, petrophysical, and facies characteristics of the Brown Limestone Formation and predict their complex geometry in 3D space. The Brown Limestone formation is considered to be as a reservoir in the study area. The value of water saturation ranges from 15 to 45%, where the value of Effective Porosity ranges from 11 to 15% for the selected potential intervals in Brown Limestone due to the highly structural setting in the study area, so Reservoir thickness was used as the proxy for reservoir effectiveness where thicker reservoir had a higher chance of containing multiple intervals for good potential intervals. [ABSTRACT FROM AUTHOR]

ΔlogR method is one of the most widely utilized techniques for estimation of Total Organic Carbon (TOC) content form well logs. The traditional ΔlogR method reveals the assumption of linear relationship between logarithmic resistivity and porosity log. In this study, the method is modified by means of integral calculus to acquire the actual trend between logarithmic resistivity and porosity log. Furthermore, unlike to the traditional method, the maturity is additionally represented with logarithm of organic maturation temperature. Nonlinear regression is applied to optimize the unclear organized parameters required for computation of TOC content. The final forms of the equations are observed to be appropriate for the nonlinear regression application. The TOC estimations are observed to be improved with the modified versions in case traditional methods are unsatisfactory due to the related assumption expressed above. With the introduced methodology the TOC of unconventional reservoirs and source rocks can be more accurately calculated.

Abstract The main objective of this paper is to understand the impact of the fractal characteristics of fractured reservoirs on their pressure behavior, flow rate decline, and productivity index. The paper proposes a new methodology for developing several analytical models for describing the wellbore pressure distribution and the flow rate decline trend. The proposed models consider including the fractal characteristics such as the mass fractal dimension, conductivity index of anomalous diffusion flow mechanism, fractal-network parameters, fractional-derivative order, and matrix/fracture-interaction index as well as dual-porosity media characteristics such as the storativity and interporosity flow coefficient in the analytical models of the pressure, rate, and productivity index. The study has found that: (1) Some of the fractal characteristics have a significant impact on reservoir performance, while others may not have a significant impact. (2) Fractal reservoirs exhibit better performance than the standard geometry reservoirs of single and dual-porosity media.

According to Araujo (2021), the concepts and conceptions about geological-geomorphological dynamics are often presented in textbooks superficially, without deepening and without a critical analysis. This research aims to propose unconventional methodologies to fill the gaps related to the contents of Geomorphology and Geology found in the textbook "Geography Contexts and Networks" by Silva, Olic and Lozano (2016) corresponding to the 1st grade of high. The methodology used is qualitative/descriptive, case study and content analysis. The study was motivated by the complexity, misconceptions and high degree of abstraction that the physical contents of Geography usually present in didactic works. It justifies the choice of theme due to the need to evaluate the natural physical contents present in textbooks, and to propose unconventional methodologies to fill the gaps present in these materials, being an important work for teachers, serving as a suggestion to address issues related to physical geography, notably Geomorphology and Geology in a meaningful, integrated and applied way in order to achieve teaching-learning and geographic reasoning of the students. It is confirmed that the insertion of digital software (games and the GIS Google Earth), models, cinema and comic books (HQs), are beautiful examples of how the teacher may be working with some concepts that present gaps or inconsistencies in the textbook "Geography Contexts and Networks". [ABSTRACT FROM AUTHOR]

Unconventional reservoirs are the productive zones in other words the rock quality and the mechanical properties of the rocks this process is devastating if humans or people try to search for the best reservoirs. So we can use machine learning (ML) algorithms to help us find and search easily and fast for the best reservoirs with less human interaction as possible. The objectives of this paper is to use machine learning (ML) techniques to predict and classify the reservoirs based on the properties of each reservoirs and choose the best reservoir. In this paper we have made a comparison between the different types of machine learning algorithm and described how we get the best and worst result for each one, the comparison we made gave us that the AdaBoost algorithm gave the worst performance measured in the accuracy while the random forest (RF) algorithm gave the best performance, this paper aim to make improvement of the process of searching for productive zones using ML algorithms. [ABSTRACT FROM AUTHOR]

Conventional oil reserves in Colombia are depleted. The country´s reserve-to-production ratio is estimated as 5 years. Therefore, the search for new resources and their conversion into proven reserves are essential. In this case, the production of unconventional reservoirs is an option in Colombia. This work evaluates the technical and economic feasibility of the production of a Tight Oil source rock reservoir, considering parameters such as fracture shape factor, fracture propagation, fracture pressure, international oil price, petrophysical characteristics, fluid properties, drilling cost, completion, and fiscal regime. The methodological development of the work allowed concluding that this reservoir located in the middle Magdalena Valley basin has production potential and those factors such as the type of completion, drilling technique, and cost of lifting the resource have a significant impact on the viability of the project.

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Faults are thought to act as barriers or conduits for intraformational hydrocarbon migration within unconventional low-permeability hydrocarbon accumulations. However, well-documented studies substantiating this phenomenon at the regional-scale are scarce. Here, we use an extensive molecular and isotopic dataset for produced-gas samples (n = 562) from the Montney unconventional hydrocarbon accumulation of northeast British Columbia to show that regional-scale secondary migration of methane-rich gas was significantly influenced by the distribution and orientation of faults. Cross-plots using iC 4 /nC 4 , δ13C ethane and δ13C propane exhibit single coherent distributions, suggesting that the C 2+ components of most of these gases share interrelated histories of generation, maturation and primary migration. Conversely, cross-plots using gas dryness and δ13C methane against other selected gas parameters demonstrate geographic differentiation, with samples from the southeastern part of the study area generally exhibiting elevated molecular concentration and isotopic enrichment of methane compared to the samples from the northwestern part of the study area. The compositional and isotopic enrichment of methane in the southeastern samples signify significant late-stage secondary migration of highly mature methane-rich gas from deeper zones to shallower zones, and mixing with in-situ hydrocarbon fluids of lower thermal maturity. Previous structural mapping documents the presence of numerous subsurface thrust-faults related to the Cordilleran orogeny in the northwestern area, while these features are entirely absent in the southeastern area. Consequently, we conclude that thrust-faults, with accompanying clay-rich gouges, formed effective en-echelon barriers to the late-stage secondary migration of methane-rich gas in the northwestern area and prevented substantial mixing of hydrocarbon fluids. [Display omitted] • Montney Formation underwent secondary migration of highly mature dry gas during basin uplift. • Gas migration was influenced by faults acting as barriers, baffles and conduits. • En-echelon thrusts with clay-rich gouges formed effective barriers to gas migration. • Areas with thrusts had notably less dry gas migration than areas without thrusts. • Mature gas migration led to isotopically enriched methane in areas lacking thrusts. [ABSTRACT FROM AUTHOR]

The Kimmeridge Clay Formation (KCF) forms the source rock for most conventional hydrocarbon accumulations within the UK North Sea. However, only a few previous studies have analyzed the potential of the KCF for unconventional resources (i.e., shale oil and gas). Here, we use machine learning techniques combined with established rock property equations to generate geochemical, petrophysical and geomechanical logs for 16 wells within Quadrant 15 of the Outer Moray Firth, UK North Sea. The neural network models used to generate geochemical logs are trained using the Levenberg-Marquardt backpropagation algorithm. The generated well logs and new KCF depth maps, constrained by an existing Base Cretaceous Unconformity (BCU) map of the UK North Sea and well top information from 48 wells, are used for 3D geostatistical modelling of KCF properties across the area. The resulting KCF property maps allow us to assess the shale oil and gas play potential across the region. Our results suggest good organic richness and hydrocarbon yield potential for the KCF within the study area, with up to 9 wt% original total organic carbon (TOC o), 48 mg/g original hydrocarbon yield (S 2o), and 607 mg/gTOC original hydrogen index (HI o). Modelled total porosity values range between 2 and 13%, and brittleness indices lie between 25 and 65%, within the range reported for proven shale oil and gas plays. A sweet spot map, created by integrating our modelled KCF properties, indicates prospective areas for shale oil and gas exploitation within the central Witch Ground Graben, and to a lesser extent areas of the Piper Shelf and Claymore-Tartan Ridge. These areas show good potential based on all investigated properties, with respect to industry standards. • The Kimmeridge Clay Formation has been evaluated for its shale oil & gas potential. • Methodology includes 3D geostatistical modelling of key evaluation parameters. • An integrated sweet spot map shows areas within the central Witch Ground Graben. • The map simplifies the identification of areas with shale oil & gas potential. [ABSTRACT FROM AUTHOR]

The Bazhenov formation is a source of unconventional hydrocarbons and a complex object of study. Oil accumulations in the Bazhenov formation are not controlled by the structural factor. In this article, based on the results of basin modeling, the priority geological and geochemical parameters that affect the distribution of unconventional hydrocarbon accumulations in the sediments of the Bazhenov formation are identified. The article describes the initial geological, lithological, petrophysical, geochemical and thermal parameters necessary for the analysis of the hydrocarbon system of the Bazhenov formation. The paper presents the results of calculating a 2D model of a regional sublatitudinal profile of the West Siberian basin. The calibration of geological and thermal models based on the data on reservoir temperatures and pressures, as well as on the vitrinite reflectance (Ro) and Tmax pyrolysis is illustrated. The analysis of the sensitivity of the model to changes in the kinetic spectrum of kerogen destruction of the Bazhenov formation has been carried out. Criteria for localization of the most promising areas of the Bazhenov shale formation are proposed. On the basis of the work done, it was shown that the basin modeling tool in combination with the results of geological and geochemical studies allows us to distinguish promising areas within bituminous formations. The key parameters are maturity of organic matter, the amount of generation and adsorption of hydrocarbons, as well as overpressure zones.

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The lower Silurian Qusaiba Shale is one of the major source rocks for Paleozoic oil/gas reservoirs in Saudi Arabia and recently considered a potential unconventional shale gas resource. The study aims to evaluate the reservoir heterogeneity and production potential of Qusaiba Shale through the integration of geological, geomechanical and fractures characteristics. Three lithofacies were identified in Qusaiba shale. Mineralogical composition resulted in variable amounts of quartz ranging from 39 to 40, 45–55 and 60–78% for Lithofacies-I, II and III, respectively. Inter-granular porosity of these lithofacies is very low; however, fractures along laminations, at angle with laminations, and few micro-faults enhance porosity up to 5–6, 2–3, and < 1% in Lithofacies-I, II and III, respectively. The Lithofacies-I hosts the lowest fracture density (1.2 fractures/foot), likely due to the relatively lower quartz content (39%) as compared to other lithofacies. The fracture densities in Lithofacies-II and III are 2.1 and 3.2 fractures/foot, respectively. Lithofacies-I exhibits low stiffness in terms of low Young's modulus (average 26 GPa) and high Poisson's ratio (average 0.34). Mineralogy- and elastic parameters-based brittleness indices exhibited ductile behavior of this lithofacies. The brittleness index exhibited brittle behavior for silica-rich Lithofacies-III and has highest intensity of natural fractures. Hence, it is concluded that mineralogy and geological characteristics are the main controlling factors on shale brittleness, mechanical properties and fractures characteristics. The integration of geology, mineralogy and geomechanics plays the key role to better evaluate the prospectivity of shale reservoirs. [ABSTRACT FROM AUTHOR]

With the implementation of the production tests in permafrost and offshore regions in Canada, US, Japan, and China, the study of natural gas hydrate has progressed into the stage of technology development for industrial exploitation. The depressurization method is considered as a better strategy to produce gas from hydrate reservoirs based on production tests and laboratory experiments. Multi‐well production is proposed to improve gas production efficiency, to meet the requirement for industrial production. For evaluating the applicability of multi‐well production to hydrate exploitation, a 2D model is established, with numerical simulations of the performance of the multi‐well pattern carried out. To understand the dissociation behavior of gas hydrate, the pressure and temperature distributions in the hydrate reservoir are specified, and the change in permeability of reservoir sediments is investigated. The results obtained indicate that multi‐well production can improve the well connectivity, accelerate hydrate dissociation, enhance gas production rate and reduce water production as compared with single‐well production. [ABSTRACT FROM AUTHOR]

ΔlogR method is one of the most widely utilized techniques for estimation of Total Organic Carbon (TOC) content form well logs. The traditional ΔlogR method reveals the assumption of linear relationship between logarithmic resistivity and porosity log. In this study, the method is modified by means of integral calculus to acquire the actual trend between logarithmic resistivity and porosity log. Furthermore, unlike to the traditional method, the maturity is additionally represented with logarithm of organic maturation temperature. Nonlinear regression is applied to optimize the unclear organized parameters required for computation of TOC content. The final forms of the equations are observed to be appropriate for the nonlinear regression application. The TOC estimations are observed to be improved with the modified versions in case traditional methods are unsatisfactory due to the related assumption expressed above. With the introduced methodology the TOC of unconventional reservoirs and source rocks can be more accurately calculated. [ABSTRACT FROM AUTHOR]

Among energy carriers, the role of oil is more remarkable in economic development of developed and developing countries. But the fluctuations in oil price, existence of constant challenges between suppliers and demanders, the beginning of descending trend of production and promoting the energy security in its consuming countries have caused besides oil, its substitutes find specific importance. Development and extraction of unconventional resources on one hand have made changes in reservoirs ranking in different areas of the world and has weakened the dependency of consuming countries and on the other hand, it has affected the changing trend of oil price. In this respect, the present study investigates the causal relationship between oil price and supplying unconventional oil and gas during time period of 2000-2015. Two techniques named Granger technique and Toda and Yamamoto technique have been used to investigate the causal relationship. The results of the research show that in all studying period (2000-2015) the unconventional supply is the strong and direct cause for oil price and the indirect and weak price are introduced as the causes of unconventional supply. Also, based on the results, the strong impact of financial markets on the supply of unconventional resources and oil prices has been achieved. On the other hands the results show that unconventional supply will affect the supply of OPEC in the long term (2000-2015). Therefore, this achievement for OPEC countries, as well as Iran, can be used as a result of a strategic change in production policy.

Near-wellbore damage, which significantly reduces hydrocarbon production, can happen during drilling, cementing, perforation, completion, and stimulation operations. The most common technique to remove or bypass this damage is matrix acidizing. The effects of matrix acidizing injection pressure on acid penetration rate, chemical reaction rate, solubility, porosity, and permeability of Marcellus core samples were investigated in this experimental study. To achieve a successful acid treatment, acid type and concentration must be carefully selected. The results of the X-ray powder diffraction (XRD) and the solubility test revealed that 15 wt.% hydrochloric acid (HCl) is the optimum acid. Matrix acidizing treatments were implemented on nine core samples, taken from Marcellus (shale gas reservoir), at the reservoir temperature (66 °C), confining pressure of 10.35 MPa, and three different acid injection pressures (1.72, 3.45, and 5.17 MPa). The results showed that performing acid treatments on the samples containing continuous carbonate layers created highly permeable channels (wormholes) resulting in significant improvement, up to 3900%, in the permeability of the samples. Additionally, the results of the acid penetration rate, chemical reaction rate, solubility, porosity, and permeability revealed that increasing the acid injection pressure resulted in increases in the aforementioned properties of the samples. The results also revealed that any increase in the injection pressure above 3.45 MPa did not demonstrate any significant enhancements in the properties of the samples. The results of the XRD analysis revealed that matrix-acidizing treatments dissolved 23.2% of calcite and 0.4% of dolomite existed in the samples. [ABSTRACT FROM AUTHOR]

The main objective of this paper is to understand the impact of the fractal characteristics of fractured reservoirs on their pressure behavior, flow rate decline, and productivity index. The paper proposes a new methodology for developing several analytical models for describing the wellbore pressure distribution and the flow rate decline trend. The proposed models consider including the fractal characteristics such as the mass fractal dimension, conductivity index of anomalous diffusion flow mechanism, fractal-network parameters, fractional-derivative order, and matrix/fracture-interaction index as well as dual-porosity media characteristics such as the storativity and interporosity flow coefficient in the analytical models of the pressure, rate, and productivity index. The study has found that: (1) Some of the fractal characteristics have a significant impact on reservoir performance, while others may not have a significant impact. (2) Fractal reservoirs exhibit better performance than the standard geometry reservoirs of single and dual-porosity media. [ABSTRACT FROM AUTHOR]

The production from shale gas reservoirs has significantly increased due to technological advancements. The shale gas reservoirs are very heterogeneous and the heterogeneity has a significant effect on the quality and productivity of reservoirs. Hence, it is essential to study the behavior of such reservoirs for accurate modelling and performance prediction. To evaluate the impact of fracture parameters on shale gas reservoir productivity using CMG (Computer Modelling Group) stars simulation software was the main objective of this study. In this paper, a comprehensive analysis considering an example shale gas reservoir was conducted for production performance analysis considering uniform and non-uniform fractures configurations. Several simulations were performed by considering the multi-stage hydraulically fractured reservoir. The sensitivities conducted includes the different cases of moderate and severe heterogeneity along with variable fractures half-length, effect of changing fracture spacing, variable fracture conductivities. The simulation results showed that by increasing conductivity of fracture increases the gas production rate significantly. Moreover, cases of reservoir permeability heterogeneity were analyzed which show the significant effect on gas rate and on cumulative gas production. The results of this study can be used to improve the effectiveness in designing and developing of shale gas reservoirs and also to improve the accuracy of analyzing heterogeneous shale gas reservoir performance. [ABSTRACT FROM AUTHOR]

This paper addresses challenges in characterizing unconventional shale reservoirs. For the first time, the nuclear magnetic resonance (NMR) and dielectric responses are integrated to characterize intact, saturated, and kerogen-rich subsurface shale samples at various maturation stages. The NMR and dielectric were measured separately using independent pieces of equipment, and all NMR and dielectric measurements were carried out at surface conditions. A comprehensive assessment is provided to address the changes induced by maturation through combined geochemical and petrophysical analyses. Shale samples from the Upper Cretaceous sequence of Jordan were characterized using Rock-Eval analysis, before and after maturation treatments. The total organic carbon (TOC) was decreased from 17.4 to 13.8 and 11.3 wt% and the pyrolyzed sulfur content was decreased from 3.32 to 0.25 and 0.15 3.18%, after maturing the samples at 250 °C for 1 and 5 days, respectively. The study employed NMR to track changes in pore structure via T 2 relaxation time and measured dielectric properties and conductivity dispersion across frequencies from 10 MHz to 1 GHz using a wideband open-ended coaxial probe. After the maturation treatments, the dielectric constant of saturated shale samples doubled, and the conductivity increased by over three times. These changes in dielectric properties can be attributed to increased fluid-rock interfacial polarization and the formation of new pore spaces during maturation. NMR findings also indicated the emergence of a new pore system within the organic matter and the development of new fractures, resulting in a 6 to 12% increase in total porosity. The results obtained indicate that maturation-induced microstructural changes have a more significant influence on the dielectric responses than alterations on total organic carbon. • Dielectric and NMR are used for the first time on intact, saturated, and kerogen-rich subsurface shale samples at various maturation stages. • The use of rock samples instead of crushed powder provides a better representation of the shale complex microstructure. • The kerogen distribution plays a significant role; scattered organic matter causes greater TOC reduction than accumulated. • · The changes in dielectric properties induced by maturation are more significant than those reported in the literature. • The changes in dielectric response upon maturation are primarily due to changes in geometry and pore connectivity. [ABSTRACT FROM AUTHOR]

Unconventional hybrid petroleum systems are partially to entirely self-sourced. Their hydrocarbons are generated within internal (intraformational) organic-rich mudstone source rocks and subsequently migrate into adjacent organic-lean reservoir beds composed of sandstone, siltstone or carbonate. Hybrid systems with volumetrically dominant reservoir-quality rocks can additionally receive hydrocarbon charge by longer-range migration from external source rocks. However, few previous studies of hybrid systems have focused on the migration and mixing of hydrocarbons from both internal and external sources. To address this shortfall, this study presents an integrated organic geochemistry and stable carbon isotope investigation of drill-core and produced hydrocarbon liquid samples from two wells in a major unconventional hybrid petroleum system in the Montney Formation of western Canada. The results reveal distinct geochemical trends with increasing depth through the upper part of the Montney Formation including decreased C 30+ biomarker compounds, increased depletion of saturate compared to aromatic δ13C values, and increased proportions of saturates and mobile oil. These trends indicate that oil from external source rocks of the overlying Doig Formation migrated into the upper part of the Montney Formation. Downward migration of externally sourced Doig oil resulted in a broad transition zone where Doig-sourced oil mixed with locally migrated lighter oil generated within internal Montney source rocks of slightly higher thermal maturity. This study sheds new light on the migration and mixing of disparate oil charges in the Montney Formation, and likely has widespread applicability to other similar unconventional hybrid petroleum systems that had hydrocarbon contributions from both internal and external source rocks. • Integrated geochemistry of core and produced oils from Doig-Montney Fm., Canada. • Oil migration from external source rocks of the Doig Fm. into underlying Montney Fm. • Mixing of Doig-sourced oil with locally migrated lighter oil generated within Montney. [ABSTRACT FROM AUTHOR]

• Collecting 489 sets of experimental data containing 3804 data points on CH 4 and/or CO 2 sorption capacity of shale and coal. • Machine learning-based modeling of single and binary sorption of CH 4 and CO 2. • Benchmarking the developed models based on the prediction of single and binary sorption versus pressure. The viability of enhanced coalbed methane recovery (ECBM) and enhanced shale gas recovery (ESGR) are abundantly explored in various studies since they present a solution for ongoing energy demand and environmental crisis. As a matter of challenge, the prediction of the gas sorption profile poses a significant obstacle in the development of such resources. In this regard, mathematical models, numerical simulations, empirical correlations, and experimental measurements suffer from over-simplification, computationally extensive calculations, time-consuming, and costly processes. This work examines different machine learning methods, from shallow to deep learning, to investigate their capability to model 3804 data points of methane (CH 4) and/or carbon dioxide (CO 2) sorption capacity in shale and coal at different thermodynamic conditions. Percentage of CO 2 in injection gas, rock type, total organic carbon (TOC), moisture, temperature, and pressure were taken as input. Hyperparameter tuning was executed by Optuna optimizer. According to the results, the random forest (RF) was the most proficient predictor for both test subsets of CH 4 (MAE = 0.0864, MSE = 0.0231, RMSE = 0.1520) and CO 2 (MAE = 0.0529, MSE = 0.0533, RMSE = 0.2308) sorption capacity. Based on the trend prediction simulation, RF predictors were able to properly capture the single and binary sorption capacities. More importantly, they successfully predict the abnormal descending behavior of CO 2 sorption in high pressures. In addition, a sensitivity analysis was carried out to acquire the importance of input features and model hyperparameters in the training process. Input feature impacts were consistent with technical expectations of geology and reservoir engineering aspects. Both models are capable of being applied to lab scale and further developed for their application in reservoir scale simulators. [ABSTRACT FROM AUTHOR]

In the last decade, exploration for unconventional hydrocarbon (shale gas) reservoirs has been carried out in Poland. The drilling of wells in prospective shale gas areas supplies numerous physicochemical measurements from rock and reservoir fluid samples. The objective of this paper is to present the method that has been developed for finding similarities between individual geological structures in terms of their hydrocarbon generation properties and hydrocarbon resources. The measurements and geochemical investigations of six wells located in the Ordovician, Silurian, and Cambrian formations of the Polish part of the East European Platform are used. Cluster analysis is used to compare and classify objects described by multiple attributes. The focus is on the issue of generating clusters that group samples within the gas, condensate, and oil windows. The vitrinite reflectance value (Ro) is adopted as the criterion for classifying individual samples into the respective windows. An additional issue was determining other characteristic geochemical properties of the samples classified into the selected clusters. Two variants of cluster analysis are applied—the furthest neighbor method and Ward’s method—which resulted in 10 and 11 clusters, respectively. Particular attention was paid to the mean Ro values (within each cluster), allowing the classification of samples from a given cluster into one of the windows (gas, condensate, or oil). Using these methods, the samples were effectively classified into individual windows, and their percentage share within the Silurian, Ordovician, and Cambrian units is determined.

This study provides a workflow and preliminary estimations of the estimated ultimate recovery (EUR) volumes for natural gas and condensate liquids in the Tuwaiq Mountain Formation, the principal target in the Jafurah Field development project in Saudi Arabia. The strategic need for the field development is reviewed and the field characteristics are outlined based on public data sources complemented with data from analogous reservoirs. The target zone in the Jafurah Basin is a carbonaceous shale, being developed with up to 10,000-ft-long multistage-fractured laterals with 30 ft perforation cluster spacing and an assumed typical 1250 ft well spacing. The field will come on stream in 2024, when the gas-gathering pipeline system, natural gas processing plant, and underground gas storage facilities will all be in place. The range of uncertainties in the key reservoir parameters is taken into account to estimate preliminary EUR volumes (P90, P50, and P10) for both gas and condensates. Based on the present and prior EUR estimations, it can be concluded that the Jafurah Basin comprises one of the largest unconventional field development projects outside of North America.

The Qusaiba Shale Formation of the Qalibah Group is the most prolific source rock for the Paleozoic petroleum system in Saudi Arabia and is recently considered as a potential unconventional shale gas reservoir. Detailed sedimentological, petrographical, and geochemical analyses were undertaken on an ~31 m thick outcrop of this organic-rich shale exposed in the northwest of Tayma City, NW of Saudi Arabia to provide a better understanding of the vertical and lateral lithofacies variations and the effects of such variations on reservoir properties. X-ray diffraction analysis reveals that clay minerals (average: 50%) and quartz (average: 28%) dominate the bulk mineralogical composition while K-feldspar, plagioclase, and pyrite occur as common to minor components in the analyzed samples. An integration of the sedimentological description, petrography and mineralogical composition allows the subdivision of the investigated outcrop section into six lithofacies. These are: Laminated organic-rich shale, Graptolitic concretion, Massive organic-rich shale, Organic-lean shale, Siltstone-shale interbedded, and Cross-stratified siltstone/sandstone lithofacies. TOC content in the laminated and massive organic-rich shale lithofacies ranges between 0.5 and 6.1 wt% (average 2.52 wt%) then it decreases upward (0.04–0.35 wt%, average 0.18 wt%) in the overlying organic-lean shale and siltstone lithofacies. Trace elements (Cu, Mo, As, Ni, Co, U and V) show positive excursions in the lowermost 20 m of the organic-rich, dark-grey shale interval and display abrupt depletions at the contact with overlying organic-lean shale. The enrichment factors of these trace elements are characterized by similar distribution patterns as their measured concentrations. Like the elements, these factors also exhibit a significant depletion at the contact between the organic-rich shale and the overlying organic-lean shale. Out of all the redox indices, V/(V + Cr), V/(V + Ni), Th/U and [Mo] s /TOC were found to best distinguish between the organic-rich and the overlying organic-lean intervals. The laminated organic-rich shale lithofacies indicate deposition of hemipelagic sediments by a relatively low energy quiet anoxic bottom water, most likely in a sulfidic conditions that were associated with a strongly restricted bottom water mass circulation at the time of its deposition. This restricted hydrographic condition was likely enhanced in the study area due to the paleotopography that was created by the deglaciation of the Early Silurian time. The TOC richness, common occurrence of pyrite and high enrichment of redox elements Mo, U and V in the organic-rich shale intervals support the existence of anoxic bottom water at the time of deposition. The abrupt decrease of the TOC and the redox sensitive elements and their associated indices from the underlying organic-rich lithofacies to the overlying organic-lean shale lithofacies is likely due to a gradual increase in oxygen level. This improved bottom water oxygenation condition might have led to a reduction in organic productivity and limited organic matter preservation in the organic-lean shale lithofacies. The graptolitic concretion lithofacies found in the sequence, refers to an in-situ, syngenetic to early diagenetic origin formed close to the sediment-water layer when there was little or no deposition or at periods characterized by low sedimentation rates. The siltstone - fine sandstone lithofacies in the topmost part of the studied section, is interpreted to indicate the dominance of high energy and highly oxygenated shallow bottom water conditions during deposition, probably in a middle to inner shelf depositional settings. The kerogen in QS is a mixture of type III (gas prone) and type IV (inert kerogen), T max values with an average of 430 °C, and VRo values (average 0.58) calculated from the T max, assigned the studied section as immature. Qualitative evaluation of porosity allows the identification of three different types of porosity including inorganic porosity, organic porosity and natural fracture porosity. Although the ductile clay minerals are the most abundant minerals in the lower part of the studied QS (average 56%), the brittle minerals (Quartz, Feldspar, and Pyrite) form an average of 42% and exhibit a uniform distribution of brittleness in the organic-rich interval. • Qusaiba Shale display a significant variability resulted in six lithofacies. • Qusaiba Shale is mainly dominated by Clay and Quartz with minors of Feldspars and Pyrite. • The paleo-topography is largely controls the deposition of Qusaiba. • T max and VRo reflect the immaturity to marginal maturity of the QS in the study area. • The lowermost part has the highest reservoir potentiality in terms of organic content and brittleness properties. [ABSTRACT FROM AUTHOR]

Fracture pattern development has been a challenging area of research in the Earth sciences for more than 100 years. Much has been learned about the spatial and temporal complexity inherent to these systems, but severe challenges remain. Future advances will require new approaches. Chemical processes play a larger role in opening‐mode fracture pattern development than has hitherto been appreciated. This review examines relationships between mechanical and geochemical processes that influence the fracture patterns recorded in natural settings. For fractures formed in diagenetic settings (~50 to 200 °C), we review evidence of chemical reactions in fractures and show how a chemical perspective helps solve problems in fracture analysis. We also outline impediments to subsurface pattern measurement and interpretation, assess implications of discoveries in fracture history reconstruction for process‐based models, review models of fracture cementation and chemically assisted fracture growth, and discuss promising paths for future work. To accurately predict the mechanical and fluid flow properties of fracture systems, a processes‐based approach is needed. Progress is possible using observational, experimental, and modeling approaches that view fracture patterns and properties as the result of coupled mechanical and chemical processes. A critical area is reconstructing patterns through time. Such data sets are essential for developing and testing predictive models. Other topics that need work include models of crystal growth and dissolution rates under geological conditions, cement mechanical effects, and subcritical crack propagation. Advances in machine learning and 3‐D imaging present opportunities for a mechanistic understanding of fracture formation and development, enabling prediction of spatial and temporal complexity over geologic timescales. Geophysical research with a chemical perspective is needed to correctly identify and interpret fractures from geophysical measurements during site characterization and monitoring of subsurface engineering activities. Plain Language Summary: Fracture patterns in rock strongly affect directions, magnitudes, and heterogeneities of both fluid flow and rock strength. Accurate and testable predictions of patterns are essential for understanding many societally important processes in the Earth and for effectively managing subsurface engineering operations. Chemical processes play a larger role in opening‐mode fracture pattern development than has hitherto been appreciated. For fractures formed at depths of ~1–10 km and temperatures of 50–200 °C, new evidence shows chemical reactions are common and more diverse than previously recognized. We describe how viewing fracture formation and evolution from a chemical perspective helps to solve problems in fracture pattern analysis. We outline the main impediments to subsurface fracture pattern measurement and interpretation, assess implications of recent discoveries in fracture history reconstruction for process‐based models of fracture and cement accumulation, review models of fracture cementation and chemically assisted fracture growth, and discuss promising paths for future work. Potential exists for basic scientific investigations to lead to progress on what has been one of the most refractory practical problems in subsurface science. Results suggest that progress in fracture interpretation and prediction can be made using observational, experimental, modeling, and theoretical approaches that view fracture patterns as the result of coupled mechanical and chemical processes. Key Points: A chemical perspective helps solve challenges to understanding subsurface fractures: inadequate samples, ambiguous analogs, and difficulties determining which models are correct from observationsMany tools of chemical analysis, experiment, modeling, and theory have yet to be brought to bear on understanding how fracture patterns develop at geological timescalesChemical and mechanical investigations together have great potential to solve challenging practical problems in subsurface science [ABSTRACT FROM AUTHOR]

The 4th member of the Upper Triassic Xujiahe Formation has become a primary target for tight gas exploitation in the western Sichuan Basin in past decades. Finding relatively high porosity reservoirs in tight sandstones is significant for successful tight gas exploration. In this study, the Xu4 sandstone was studied by a variety of experimental methods, including core observation, thin-section and cathodoluminescence observation, porosity and permeability measurement, mercury intrusion, scanning electron microscopy, X-ray diffraction, electron probe micro-analyzer and fluid inclusion, to determine the reservoir characteristics and also diagenesis evolution and to discuss their impacts on the reservoirs. The Xu4 sandstones are mainly litharenites, feldspathic litharenites and sublitharenites. Among these, calcarenaceous sandstone (CS sandstone) and sandstone with a high kaolinite content (KS sandstone) are classified by their special compositions. The reservoir quality of the Xu4 sandstone is poor, and among the five types of sandstone, the reservoir quality of the KS sandstone is generally better than that of the other types. The diagenetic variations of the Xu4 sandstone are complicated by compaction, kaolinite and quartz cementation, two stages of carbonate cementation, and two stages of dissolution of feldspar and some unstable rock fragments. The KS sandstone is the product of feldspathic litharenite that underwent early-stage dissolution of feldspar during eodiagenesis because of the acidic fluids in the sandstone. This process resulted in a low K+/H+ ratio of the pore fluids, i.e., acidic fluids derived from atmospheric fresh water and fluids of adjacent strata bearing coal seams. The determination of the diagenetic evolution indicated that the poor reservoir quality can be attributed to strong compaction or extensive cementation (mainly calcite cementation). However, the occurrence of relatively high porosity reservoirs varies among the sandstones. For CS sandstone, weak early carbonate cementation is essential. For sublitharenite, feldspathic litharenite, and litharenite, late dissolution of feldspar and less cement are necessary for the formation of relatively high-quality reservoirs. Due to their high porosity, almost all of the KS sandstones are relatively high-quality reservoirs. • Five types sandstone classified based on lithological characteristics. • Two stages of carbonate and quartz cementation and dissolution has been undergone. • Diagenetic and porosity evolution of various sandstones were established to predict the relatively high-quality reservoir. [ABSTRACT FROM AUTHOR]