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The past decades have witnessed the increased applications of induced polarization (IP) method in the critical zone studies with ubiquitous clay minerals. Although IP outperforms traditional electrical and electromagnetic methods through its unique ability to measure quadrature conductivity, the nonlinearity that quadrature conductivity behaves with salinities and frequencies greatly tortures IP practitioners, as (a) salinity-dependency makes the quadrature conductivity a varyingly unstable parameter to quantitatively estimate hydraulic properties and clay content; (b) frequency-dependent Cole-Cole and Debye/Warburg decomposition models, although mathematically sound, physically mingle the properties of pore water and clay minerals and are empirical in nature. From basic principles, we demonstrate that quadrature conductivity remains a hybrid property involving both clay and water, and develop relevant models to distinguish them. Our models are validated by theories, experiments, simulations, and comparisons, all of which proclaim considerable advantages over previous models and offer the prospect of quantitative applications.

Tight sandstone reservoirs, despite their low porosity and permeability, present considerable exploration potential as unconventional hydrocarbon resources. Natural fractures play a crucial role in hydrocarbon migration, accumulation, and present engineering challenges such as late-stage reformation in these reservoirs. This study examines fractures in the seventh member of the Triassic Yanchang Formation's tight sandstone within the Ordos Basin using a range of methods, including field outcrops, core samples, imaging and conventional logging, thin sections, and scanning electron microscopy. The study clarifies the characteristics of fracture development and evaluates the relationship between dynamic and static rock mechanics parameters, including the calculation of the brittleness index. Primary factors influencing fracture development were quantitatively assessed through a combination of outcrop, core, and mechanical test data. Findings reveal that high-angle structural fractures are predominant, with some bedding and diagenetic fractures also present. Acoustic, spontaneous potential, and caliper logging, in conjunction with imaging data, enabled the development of a comprehensive probabilistic index for fracture identification, which produced favorable results. The analysis identifies four key factors influencing fracture development: stratum thickness, brittleness index, lithology, and rock mechanical stratigraphy. Among these factors, stratum thickness is negatively correlated with fracture development. Conversely, the brittleness index positively correlates with fracture development and significantly influences fracture length, aperture, and linear density. Fractures are most prevalent in siltstone and fine sandstone, with minimal development in mudstone. Different rock mechanics layer types also impact fracture development. These insights into fracture characteristics and controlling factors are anticipated to enhance exploration efforts and contribute to the study of similar unconventional reservoirs. [ABSTRACT FROM AUTHOR]

The electrical properties of rocks are widely used in the geophysical exploration of natural resources, such as minerals, hydrocarbons and groundwater. In mining exploration, the primary goal is to map electrically anomalous geological features associated with different mineralization styles, such as clay alteration haloes, metal oxides and sulphides, weathered crystalline rocks or fractured zones. As such, the reconciliation of geophysical data with geological information (geochemistry, mineralogy, texture and lithology) is a critical step and can be performed based on petrophysical properties collected either on core samples or as downhole measurements. Based on data from 189 diamond drill cores collected for uranium exploration in the Athabasca Basin (Saskatchewan, Canada), this paper presents a case study of reconciliation of downhole resistivity probing with core sample geochemistry and short‐wave infrared spectroscopy (350–2500 nm) through three successive steps: (i) multivariate analysis of resistivity and other petrophysical properties (porosity, density) against geochemical and infrared spectroscopy information to characterize electrical properties of rocks with respect to other physical parameters, (ii) a machine‐learning workflow integrating geochemistry and spectral signatures in order to infer synthetic resistivity logs along with uncertainties. The best model in the basin was Light Gradient‐Boosting Machine with pairwise log‐ratio, which yielded a coefficient of determination R2 = 0.80 (root mean square error = 0.16), and in the basement, support vector regression with data fusion of infrared spectroscopy and pairwise log‐ratios on geochemistry yielded R2 = 0.82 (root mean square error = 0.35); (iii) the best model was then fitted on an area that was excluded from the original dataset (Getty Russell property) in order to infer synthetic resistivity logs for that zone. Software code is publicly available. This workflow can be re‐used for the valorization of legacy datasets. [ABSTRACT FROM AUTHOR]

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources. [ABSTRACT FROM AUTHOR]

Microbialite reservoirs are of great importance in oil and gas exploration. However, there is still a lack of comprehensive studies on the formation mechanisms of thrombolitic reservoirs, a specific type of microbialite. This research focuses on the oldest thrombolitic dolomite reservoir located within the Precambrian Dengying Formation in the central Sichuan Basin, southwestern China. A multi-disciplinary approach was employed to characterize different thrombolite facies and elucidate the formation mechanism of thrombolitic dolomite reservoirs and their controlling factors, involving core observation, thin-section analysis, cathodoluminescence, scanning electron microscope (SEM) microscopy, elemental analysis using LA-ICP-MS, and carbon and oxygen stable isotope analysis. Based on variations in texture, four types of thrombolite were identified: 1) distinct clotted thrombolite, 2) diffuse and regular clotted thrombolite, 3) diffuse and irregular clotted thrombolite, and 4) composite clotted thrombolite. Notably, the diffuse clotted thrombolitic dolomite is the prevalent lithology in the reservoir. Through modification by meteoric water, organic acid fluids, and hydrothermal fluids, a reservoir with dominant porosity in the form of primary growth-framework pores, dissolution pores, and vugs was formed. This resulted in the development of two high-quality reservoir intervals within the Second Member and at the top of the Fourth Member of the Dengying Formation. The growth-framework porosity of the thrombolites, epigenetic karstification, and tectonic fracturing were mainly conducive to reservoir development. However, various types of cementation have reduced porosity and connectivity within the reservoir. Overall, this study is a valuable example of the methodology required to understand meso- and microstructures of deep-buried thrombotic dolomite reservoirs, including their heterogeneities and diagenesis, as the original structures influence diagenesis. [ABSTRACT FROM AUTHOR]

Laboratory modeling of in-situ combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 ℃, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO2 storage. In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and postcombustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction. The analysis shows a significant increase in carbonate rocks' porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%e20%, and formation of new pores is registered at the scale of 1e30 mm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new mineralsdanhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO2 trapping with greater capacity. Consequently, these findings highlight the importance of laboratory in-situ combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO2 storage. [ABSTRACT FROM AUTHOR]

Aragonite is a metastable mineral, which is easily transformed into calcite, and generally difficult to preserve in the stratum. However, large amounts of aragonites were found in the Paleogene shale of the Jiyang Depression. The characteristics and preservation mechanisms of these aragonites were analyzed through a series of analytical methods, including cathodoluminescence, field-emission scanning electron microscopy (FESEM), laser ablation inductively coupled plasma mass spectrometry (LA-ICP-MS), microarea carbon and oxygen isotopes, Sr isotopes, and dissolution simulation experiments under high temperature and high pressure. The research results show that: ①Aragonite in the Paleogene shale of the Jiyang Depression is related to algal microbial fossils, primarily composed of coccoliths and characterized by two emission peaks at 420 nm and 480 nm in cathodoluminescence; ②The primary factor allowing biological aragonite to be preserved is the immaturity of the organic matter and the deficiency of abundant organic acids necessary for its dissolution or transformation, which is confirmed by the evidence of organic matter maturity and simulation experiments of organic acid dissolution on aragonite under high-temperature and high-pressure conditions. Additional factors that may aid in the preservation of aragonite are the ideal sedimentation conditions, the defense of organic coating, and the enclosed environment with tiny pores, low porosity, and low permeability; ③These aragonite-rich shales, characterized by coccolithophores, provide a solid evidence for seawater intrusion into terrestrial lake basin, and have a significant implication for the source and storage of shale oil. [ABSTRACT FROM AUTHOR]

In this study, an integrated approach for diagenetic facies classification, reservoir quality analysis and quantitative wireline log prediction of tight gas sandstones (TGSs) is introduced utilizing a combination of fit-for-purpose complementary testing and machine learning techniques. The integrated approach is specialized for the middle Permian Shihezi Formation TGSs in the northeastern Ordos Basin, where operators often face significant drilling uncertainty and increased exploration risks due to low porosities and micro-Darcy range permeabilities. In this study, detrital compositions and diagenetic minerals and their pore type assemblages were analyzed using optical light microscopy, cathodoluminescence, standard scanning electron microscopy, and X-ray diffraction. Different types of diagenetic facies were delineated on this basis to capture the characteristic rock properties of the TGSs in the target formation. A combination of He porosity and permeability measurements, mercury intrusion capillary pressure and nuclear magnetic resonance data was used to analyze the mechanism of heterogeneous TGS reservoirs. We found that the type, size and proportion of pores considerably varied between diagenetic facies due to differences in the initial depositional attributes and subsequent diagenetic alterations; these differences affected the size, distribution and connectivity of the pore network and varied the reservoir quality. Five types of diagenetic facies were classified: (i) grain-coating facies, which have minimal ductile grains, chlorite coatings that inhibit quartz overgrowths, large intergranular pores that dominate the pore network, the best pore structure and the greatest reservoir quality; (ii) quartz-cemented facies, which exhibit strong quartz overgrowths, intergranular porosity and a pore size decrease, resulting in the deterioration of the pore structure and reservoir quality; (iii) mixed-cemented facies, in which the cementation of various authigenic minerals increases the micropores, resulting in a poor pore structure and reservoir quality; (iv) carbonate-cemented facies and (v) tightly compacted facies, in which the intergranular pores are filled with carbonate cement and ductile grains; thus, the pore network mainly consists of micropores with small pore throat sizes, and the pore structure and reservoir quality are the worst. The grain-coating facies with the best reservoir properties are more likely to have high gas productivity and are the primary targets for exploration and development. The diagenetic facies were then translated into wireline log expressions (conventional and NMR logging). Finally, a wireline log quantitative prediction model of TGSs using convolutional neural network machine learning algorithms was established to successfully classify the different diagenetic facies. [ABSTRACT FROM AUTHOR]

The Amal oil field is located in the southern part of the Gulf of Suez and produces hydrocarbons mainly from middle Miocene reservoirs. It is marked by uncertainties in the southern part of the Gulf of Suez province because of the structural complexity, lateral facies change, different lithologies, and diverse reservoir quality. Therefore, in this approach, different reservoir properties of the Hammam Faraun Member of the Belayim Formation, the Markha Member of the Kareem Formation, and the Upper Rudies Member are obtained and evaluated. The main reservoirs are composed of sand and shale intercalations. The wireline logging data (gamma ray, density, neutron, sonic, and resistivity logs) of four wells were used mainly for the petrophysical analyses of hydrocarbon reservoirs. The three most important parameters in petrophysical evaluation: shale content, porosity, and fluid saturation are calculated for the main reservoirs to construct the litho-saturation model for each well. Each of these parameters is mapped to study their areal variation across the study area and estimate the appropriate locations for the new development wells. Fluid saturations are estimated based on the Indonesian formula due to shale presence. The study exhibited that Hammam Faraun, Markha, and Upper Rudies Formations have porosity of 0.15-0.17, 0.15-0.23, 0.12-0.27; shale volume of 0.3-0.36, 0.12-0.51, 0.19-0.37; and water saturation of 0.34-0.6, 0.33-0.51, 0.48-0.6, respectively. The results show an increasing trend toward the central part in porosity, sandy facies, and oil saturation. Based on the petrophysical evaluation and the mapping, the central part of the field is very promising for development and production activities. [ABSTRACT FROM AUTHOR]

The Zeit sand reservoir is one of the most prolific formations at Northwestern side of the Gulf of Suez. In this research we will try to coordinate between electrical, petrophysical properties, dep-ositional environment and facies discrimination in order to evaluate the hydrocarbon potentiality of studied Zeit Formation. The statistical parameters for potassium (K), thorium (Th) and Th/U ratio contents have a general increase towards northwestern parts, whereas uranium (U) content has a general increase towards southeastern parts. The sandstone facies is distinguished from the other facies by its thorium content >4 ppm. U has high carbonate content (U ≽ 1 ppm). Rocks' electrical properties vary greatly depending on a number of factors. Electrical measurements were taken at frequencies range of (5 × 10−4 Hz–100 kHz) for fully saturated samples (clayey sandstone) with NaCl (20 gm/L). As salinity, clay content, and frequency increase, consequently does the electrical properties. The continental condition are present in northwestern part (back-sea) which is distinguished by high K percent, high Th, high Th/U ratio, and low U contents. Low K, Th, and Th/U ratio contents, with high U contents, characterize the marine depositional environment that existed around the east and southeastern parts (fore-sea coincide with the dipping of strata). Furthermore, the studied Zeit Formation has good petrophysi-cal properties that coincide with marine conditions. The middle and eastern parts (around ISS-94 and CSS-288) is a good reservoir (porosity 36%–39%, shale content <15%, hydrocarbon saturation 71%–92%, and net pay thickness 17–63 feet). [ABSTRACT FROM AUTHOR]

Total Organic Carbon (TOC) is one of the most important geochemical parameters in source rock evaluation, utilized to characterize the hydrocarbon generation potential. Artificial intelligence (AI) methods have significant features, including decreased time and high cost-effectiveness, providing a sufficient database, reducing risk, and enabling better decision-making. AI methods based on these significant features have become efficient tools in various approaches to geological studies such as prediction and classification. This study uses an artificial neural network (ANN), and ensemble algorithms including random forest, bagging, and least-square boosting to evaluate the organic richness of the Kazhdumi Formation in the Persian Gulf. The Kazhdumi Formation with Cretaceous age is well-known as one of the most important source rocks in the Zagros and NW of the Persian Gulf. The obtained results of Rock-Eval pyrolysis and conventional well logs e.g., sonic, neutron, density, spectral gamma-ray, resistivity, and acoustic impedance are utilized for TOC estimation. The performance of AI algorithms was analyzed using root mean squared error (RMSE) and mean absolute error (MAE) equations and the obtained results from the error evaluation analysis show that the least square boosting (LSB) algorithm has the lowest error than the other proposed algorithms in this investigation. The cross-validation analysis between the determined TOC values of blind samples of Rock-Eval pyrolysis and the AI algorithms e.g., the ANN and random forest, bagging, and least-square boosting are evaluated 0.89, 0.90, 0.94, and 0.95, respectively. The geochemical study of the Kazhdumi Formation as a potential source of rock shows that this formation has a good potential for hydrocarbon generation. According to the geochemical evaluation based on the cross-plot analysis, the Kazhdumi Formation contains type II, and type II-III kerogen, which is affected by the sedimentation conditions of this formation. This investigation has confirmed the ability of ensemble methods for TOC value estimation, and it can further be applied to investigate other geological properties. [ABSTRACT FROM AUTHOR]

Carbonates in the Lower Cretaceous (Barremian to early Aptian) Kharaib Formation are reservoir rocks at giant oil fields in the UAE and Qatar. The Barremian Kharaib‐2 member (K60), the focus of this study, is in general composed of a regionally continuous succession of high‐energy, shallow‐water limestones bounded above and below by "dense" low‐energy mud‐rich strata. Despite several decades of research, conventional carbonate facies classification schemes and resulting facies groupings for the Kharaib‐2 member have failed to show a statistically acceptable correlation with core‐ and log‐derived petrophysical data. Moreover, sedimentary bodies potentially responsible for dynamic reservoir heterogeneities have not clearly been identified. This paper proposes a standardized facies classification scheme for the Kharaib‐2 carbonates based on vertical facies proportion curves (VPCs) and variogram analyses of core data to construct stratigraphic correlations at both field and regional scales. Data came from 295 cored wells penetrating the Kharaib‐2 member at ten fields in the on‐ and offshore UAE. Thin, dense intervals separating reservoir units were adopted as fourth‐order transgressive units and were used for stratigraphic correlation. Field‐scale probability maps were used to identify sedimentary bodies such as shallow‐water rudistid shoals. Regional stratigraphic correlations of the Kharaib‐2 member carbonates based on the VPCs identified variations in depositional environments, especially for the lower part of the reservoir unit; depositional facies at fields in the SE of the UAE were interpreted to be more distal compared to those at offshore fields to the NW. At a field scale, the VPCs failed to identify significant lateral variations in the carbonates. However, variogram analyses of cored wells showed spatial concentrations of specific facies in the inner ramp domain which could be correlated with high‐energy depositional bodies such as shoals dominated by rudist debris. The bodies were sinusoidal in plan view with lengths of up to 8 km and widths of ca. 1 km. Although similar‐shaped bodies with these dimensions have been reported from other carbonate depositional systems, they have not previously been reported in the Kharaib Formation. At a regional (inter‐field) scale, the stratigraphic correlation of standardized sedimentary facies remains problematic; however, mapping of facies associations and their relative proportions relative to their environments of deposition demonstrated new patterns for the stratigraphic architecture of the Kharaib‐2 member in the UAE. [ABSTRACT FROM AUTHOR]

Volcanic oil and gas resources are abundant and have been one of the principal focuses of research in the oil and gas industry for a long time. Due to the complexity of the volcanogenesis and the non-homogeneity of the reservoir, the construction of a reasonable volcanic rock petrophysical model to guide the reservoir prediction is the key to success or failure. Unlike conventional sedimentary reservoirs, volcanic rock skeletons have diverse mineralogical compositions and pore structures, making the construction of equivalent petrophysical models highly complicated. This paper proposes a method to construct equivalent petrophysical models of complicated volcanic rocks with multiple mineral components and pore structures utilizing conventional logging curves. In the middle basal volcanic rock development area of the Songnan Fault, the errors in mineral content calculation and transverse wave estimation are less than 10% when comparing the results of elemental capture spectroscopy (ECS) logging and core test analysis; meanwhile, it directs the volcanic rock phase-controlled pre-stack inversion work and upgrades the accuracy of volcanic rock well seismic multi-scale reservoir prediction. [ABSTRACT FROM AUTHOR]

Low-field nuclear magnetic resonance (LF-NMR) technology plays a growing role in studying reservoirs for oil displacement characteristics. To better explore the reservoir characteristics of Da'anzhai in the Sichuan Province of China, this paper uses LF-NMR imbibition flooding experiments to study the improvement of oil displacement efficiency for shale oil reservoirs in Southwest China by different imbibition flooding technologies. In this article, experiments in scanning electron microscopy, X-ray diffraction analysis, and rock mechanics were conducted to analyze the geological features of the reservoir in the study area. In combination with the test results of the nuclear magnetic resonance method, the field technology has been reformed to improve the oil recovery efficiency. The results show that the Da'anzhai area is mainly composed of interbedded shale and limestone, with a relatively low organic carbon content and low average porosity. The pores shouted are predominantly concentrated in the range of 1–100 nm, and there are micrometer-sized pores. The mineral composition of the area is primarily quartz, dolomite, and calcite, rich in clay minerals. The degree of the development of natural fractures is not high, and the mean coefficient of stress differential in two directions is 0.19. The content of brittle minerals is greater than 50%, meaning that the overall compressibility is good. The results of the stratified T2 test show that the imbibition efficiency of shale in this area is low. The imbibition efficiency of the three cores is the best in 0–20 mm, and the imbibition efficiency is low in the 40–60-mm section. The optimum imbibition formula 2 has an apparent promoting effect on the imbibition of shale in this area. Based on the optimal formula system of imbibition flooding experiments, the average reservoir volume of reconstruction (SRV) in the Sichuan Basin increased from 39 million cubic meters to 46 million cubic meters. The oil production test went from "seeing boiling oil" to almost 2 tons/day, making a significant breakthrough in "oil production." As a result, LF-NMR technology is used to investigate the effects of core imbibition and oil displacement. The results can be used as a guide for applying on-site oil production technology transformation, which is of constructive importance for improving production. [ABSTRACT FROM AUTHOR]

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The Early Bartonian Reneiche/Siouf member is one of the primary conventional carbonate oil/gas reservoirs to be assessed in Tunisia that demands detailed evaluation. Accurate zonation and modeling of this reservoir require an integrated approach combining surface and subsurface studies. This research focuses on the depositional, diagenetic, and stratigraphic factors affecting reservoir quality and porosity within the Reneiche/Siouf member, utilizing an integrated surface-subsurface analysis. The primary aim is to understand the reservoir zonation of the Reineche Member near Kerkennah archipelago (eastern Tunisian offshore) and its lateral equivalents in central Tunisia the Siouf Member (outcrop analogue). Gamma-ray and sonic logs from the Reineche Member in the southern and southeastern Pelagian Platform (Tunisian offshore) identify three distinct limestone units (A, C, and E). These units transition into a single mud-dominated limestone unit (C) to the east and northeast of the Kerkennah archipelago. In contrast, the western Pelagian Platform (onshore) and Central Tunisia present a different stratigraphy for the Reineche/Siouf Member, comprising two limestone units: the Lower Reneiche Limestone (LRL) and the Upper Reneiche Limestone (URL), corresponding to Units C and E, respectively, separated by the Upper Reneiche Shale (URS) unit. Reservoir porosity and permeability analyses of the outcrop analogs reveal hybrid pore types (depositional and diagenetic), including intragranular, biomouldic, and vuggy pores, resulting from significant dissolution of large bioclasts. In the northern Gulf of Gabes, the Nummulite barrier of the Reineche Member (SW of the Kerkennah archipelago) demonstrates substantial reservoir quality improvement, with porosity reaching up to 30% in Unit C, attributed to intense dissolution, dolomitization (intercrystalline porosity), and fracturing. Diagenetic processes observed in the Siouf Member (Central Tunisia) differ from those in the Reineche Limestone Member (Pelagian Platform). In the Reineche Member, CO2-rich fluids entering through faults and fissures during deep burial diagenesis drive dissolution and dolomitization. Conversely, in the Siouf Member, these processes occur due to short subaerial exposures during meteoric to shallow-burial diagenesis. A key outcome of our study is the comparison between Central Tunisia and the eastern Tunisian offshore, highlighting local tectonic control on reservoir thickness and identifying three upward-thickening sequences in the Siouf Member outcrop. This research is crucial for understanding the Gulf of Gabes and Libyan offshore nummulitic Eocene reservoirs, emphasizing the role of tectonics and sea level changes in shaping reservoir characteristics. [ABSTRACT FROM AUTHOR]

The aim of this study is to improve hydrocarbon reservoir estimation by combining the deterministic and probabilistic approaches in an improved volumetric model with the objective of reducing geological uncertainties and achieving better reserve estimations. The case study was made in the Rio Del Rey basin of Cameroon. To achieve this goal, a mathematical model was built using the volumetric expression of the stock tank original oil in place (STOIIP), the Raymer–Hunt expression of porosity and transit time, and the Simandoux model modified by the Schlumberger expression of water saturation. The application and validation of the proposed model were made through Interactive Petrophysics, Petrel software, and Monte Carlo simulation on Minitab Workspace. The results obtained by a deterministic approach on the investigated area of 2000 m2 give a total estimated quantity of oil in place of 11897.67 MMbbl, a total estimated quantity of gas in place of 27.79 Bcf, a total estimated quantity of recoverable oil of 3606.28 MMbbl, and a total estimated quantity of recoverable gas of 19.52 Bcf. The probabilistic approach permitted to obtain an estimated quantity of oil in place of 150194141.45 MMbbl. In this study, it appears that the net value added is $288,898,222. This therefore confirms the accuracy of the model and the profitability of the project. [ABSTRACT FROM AUTHOR]

AbstractThis study presents a comprehensive characterization of the Pliocene reservoir formation in the Temsah gas field, located 65 km NNW of Port Said in the northeastern Nile Delta Basin. The research integrates seismic data with well log analysis to enhance reservoir characterization. The Temsah gas field is distinguished by its intricate geological structure, featuring numerous normal faults oriented along northeast-southwest and northwest-southeast trends. The field’s stratigraphy is predominantly composed of sandstone and shale facies, which are considered highly prospective for hydrocarbon accumulation. A full geological field analysis was conducted to identify key prospects for enhancing productivity. To accurately delineate seismic features, data from four wells and twenty-nine 2D seismic lines were interpreted. Depth maps of the reservoir layers were constructed, highlighting critical transitions between sandstone and shale facies, which are pivotal for future exploration efforts. A detailed 3D static model was developed to illustrate the impact of lithological composition on reservoir characteristics, with a specific focus on the Upper Sand of Kafr El-Sheikh Formation. Petrophysical properties, including effective porosity (13–23%), shale content (7–31%), and water saturation (30–45%), were meticulously evaluated to inform the creation of a robust 3D property model. This model provides a detailed spatial distribution of rock facies and petrophysical parameters within the Temsah gas field. The integration of these studies identified two promising areas, with estimated original gas in place (OGIP) ranging from 2.86 to 4.04 stock cubic feet (SCF), indicating significant potential for field development and enhancement. [ABSTRACT FROM AUTHOR]

Understanding the heterogeneity of reservoirs is crucial for enhancing the efficiency of hydrocarbon exploration and development. The primary porosity of samples from modern braided river sands and outcrops of braided river sandstone was calculated using a model previously proposed by the authors. The characteristic parameters (Vx) for calculating primary porosity are closely related to the architectural–elemental configurations (AEC), and the AEC of braided river sand bodies (BRSD) has apparent effects on the distribution of the primary porosity heterogeneities. Analysis of our results has established a simple primary porosity heterogeneity model of BRSD. The center of braided river channel and mid-channel bars have excellent strong primary petrophysical properties with high primary porosity exceeding 38%. The contact areas between the braided river channel and channel bars exhibit relatively low primary porosities of less than 33%. The area between the center and edge of the braided bars and channels displays medium primary porosities. The nonlinear correlation in the Q–Q plot of the primary porosity and present porosity of samples from BRSD in the Ahe Formation is mainly caused by chemical diagenesis. The present porosity heterogeneity of BRSD in the Ahe Formation is less influenced by compaction and cementation, it predominantly arises from the differential of dissolution. Q–Q plots attempt to correlate the geological information from an individual sample with the heterogeneity of present porosity in BRSD. In addition, by utilizing Q–Q plots of the primary and current petrophysical properties of the sand body, the relative extent of heterogeneity modification caused by different diagenetic processes can be assessed. This assessment is crucial for modeling macroscopic models of physical properties during geological history periods. [ABSTRACT FROM AUTHOR]

The characterisation of the thickness and geology of cover sequences significantly improves targeting for mineral exploration in buried terrains. Audio-frequency Magnetotelluric (AMT) data is applicable to characterise cover sequences, where their conductivity (inverse resistivity) can be differentiated. We present a regional study from the under-cover East Tennant region in the Northern Territory (Australia) where we have applied deterministic and probabilistic inversion methods to derive 2D and 1D resistivity models. We integrated these models with information of co-located basement penetrating boreholes (lithological and geophysical logs) to ground-truth and validate the models and to improve geophysical interpretations. In the East Tennant region, borehole lithology and wireline logging demonstrate that the modelled AMT response is largely controlled by the mineralogy of the cover and basement rocks. The bulk conductivity is due primarily to bulk mineralogy and the success of using the AMT models to predict cover thickness is shown to be dependent on whether the bulk mineralogy of cover and basement rocks are sufficiently different to provide a detectable conductivity contrast. Our investigation of a range of geological scenarios that differ in thickness, complexity and geology of the cover and basement rocks suggests that in areas where there is sufficient difference in bulk mineralogy and where the stratigraphy is relatively simple, AMT models predict the cover thickness with high certainty. In more complex scenarios interpretation of AMT models may be more ambiguous and requires integration with other data (e.g. drilling, wireline logging, potential field modelling). Overall, we conclude that the application of the method has been validated and the results compare favourably with borehole stratigraphy logs once geological (i.e. bulk mineralogical) complexity is understood. This demonstrates that the method is capable of identifying major litho-stratigraphic units with resistivity contrasts. Our results have assisted with the planning of regional drilling programs and have helped to reduce the uncertainty and risk associated with intersecting targeted stratigraphic units in covered terrains. [ABSTRACT FROM AUTHOR]

This study presents an integrated formation evaluation of the Middle Miocene syn-rift sandstones of the Hammam Faraun Member from the southern Gulf of Suez. Core data, XRD, wireline logs, and gas chromatography data have been utilized to assess the reservoir characteristics. Three lithofacies are identified from the cored intervals: (i) fine to medium-grained massive sandstone (F-1), (ii) low-angle cross-bedded fine-grained sandstone (F-2); and (iii) coarse to very coarse-grained massive sandstone (F-3). The dominantly massive nature of the sand units with sharp erosive base and bottom rip-up clasts strongly indicates a high energy channel or fan deposit. XRD analysis reveals quartz and feldspar to be the dominant constituents of this calcareous arkose. Montmorillonite and kaolinite are the major clay phases, along with minor illite. Routine core analysis of a total of 168 core plugs indicates meso- to megaporous sandstones with porosity up to 28% and Kh up to 1171 mD. Permeability anisotropy analysis exhibits the dominance of primary depositional fabric and isotropic pores. Wireline log analysis yielded shale volume < 0.2 v/v, porosity ~ 0.18–0.24 v/v, and water saturation ~ 0.33–0.49 v/v. Various gas ratios (wetness, balance, character, and oil indicator ratio) estimated from the chromatograph data indicate the presence of liquid hydrocarbons within the studied reservoirs. The study concludes excellent reservoir properties in the Hammam Faraun clastic intervals of the Esh El Mellaha area.Highlights: Hammam Faraun reservoirs consist of meso-megaporous calcareous arkose. Massive sands with sharp erosive base and bottom rip-up clasts indicates a high energy tidal deposit. Wireline logs indicate poor shale volume and considerable hydrocarbon saturation. Gas chromatography data confirms the presence of liquid hydrocarbon. [ABSTRACT FROM AUTHOR]

Tight carbonate reservoirs are complicated by their vast heterogeneity, which is attributed to diagenetic and depositional processes. The new discovery of natural gas in the tight carbonate reservoir of the Upper Cretaceous Kawagarh Formation (KF− UC) in Pakistan makes it crucial to study the factors controlling reservoir properties. This study investigated the sedimentology and reservoir characteristics of KF− UC using integrated petrography, scanning electron microscopy and energy-dispersive X-ray spectroscopy (SEM-EDS), and petrophysical techniques. The microfacies analysis of KF− UC indicates mudstone and wackestone, identified in the proximal and distal outer ramp settings of the homoclinal carbonate ramp. Diagenetic processes such as compaction, micritization, dolomitization, cementation, neomorphism, and dissolution, which represent meteoric and marine phreatic mixing zones and burial diagenetic settings, have modified the reservoir characteristics of KF− UC. The net porosity of KF− UC could be enhanced by dolomitization, dissolution, and fracturing, making it a better petroleum reservoir. With an average porosity of 2.3%, microporosities such as intercrystalline/interparticle, intracrystalline/intraparticle, vuggy, and fracture were identified in KF− UC, designating it as a tight carbonate reservoir. The outcrop and well data exhibit excellent correlation; nevertheless, the well’s net pay is inadequate due to the influence of complex tectonic structures along significant faults within the study area. Furthermore, the results of this study were compared with the Gurpi Formation of Zagros Basin, Iran, and the Aruma Formation of Central Saudi Arabia, highlighting similar sedimentological characteristics, thus emphasizing the need to initiate such projects in other regions with similar settings to further strengthen petroleum exploration. [ABSTRACT FROM AUTHOR]

The heterogeneity in permeability of coal reservoirs is primarily attributed to the considerable variation in the morphologies and structures of microscopic pore‐fractures, shaped by complex geological processes. This study emphasizes the necessity of understanding the impact and governance of these morphological and structural variations in pore‐fractures across different types of coal bodies on their permeability. Utilizing computerized tomography scanning and three‐dimensional imaging, we examined coal samples from the Datong coalfield in the southeastern Qinshui Basin, Shanxi Province, to characterize the pore‐fracture morphologies and structures distinct to various coal‐body types based on tomographic data. This introduces a methodology for assessing the influence of microscopic pore‐fracture parameters, such as porosity, specific surface area, tortuosity and fractal dimension, on permeability sensitivity. This is achieved through the application of the modified Kozeny–Carman equation and a fractal permeability model. Findings indicate a predominance of slab fractures in raw coal, whereas fragmented coal under weak brittle deformation exhibits small, isolated pore‐fractures with minimal diameter and volume and poor connectivity. In contrast, granular coal subjected to strong brittle deformation features extensive clusters of large pore‐fractures with significant diameter and volume, enhancing connectivity. Moreover, permeability predictions are refined by integrating the modified Kozeny–Carman equation with tomographic data, offering a more precise understanding of the permeability across different coal bodies. [ABSTRACT FROM AUTHOR]

S‐wave velocity plays a crucial role in various applications but often remains unavailable in vintage wells. To address this practical challenge, we propose a machine learning framework utilizing an enhanced bidirectional long short‐term memory algorithm for estimating S‐wave sonic logs from conventional logs, including P‐wave sonic, gamma ray, total porosity, and bulk density. These input logs are selected based on traditional rock physics models, integrating geological and geophysical relations existing in the data. Our study, encompassing 34 wells across diverse formations in the Delaware Basin, Texas, demonstrates the superiority of machine learning models over traditional methods like Greenberg–Castagna equations, without prior geological and geophysical information. Among these machine learning models, the enhanced bidirectional long short‐term memory model with self‐attention yields the highest performance, achieving an R‐squared value of 0.81. Blind tests on five wells without prior geologic information validate the reliability of our approach. The estimated S‐wave velocity values enable the creation of a basin‐scale S‐wave velocity model through interpolation and extrapolation of these prediction models. Additionally, the bidirectional long short‐term memory model excels not only in predicting S‐wave velocity but also in estimating S‐wave reflectivity for seismic amplitude variation with offset applications in exploration seismology. In conclusion, these S‐wave velocity estimates facilitate the prediction of further elastic properties, aiding in the comprehension of petrophysical and geomechanical property variations within the basin and enhancing earthquake hypocentral depth estimation. [ABSTRACT FROM AUTHOR]

Pore types in carbonate reservoirs are more complex than their sandstone counterparts due to the wide spectrum of their depositional environments and their more complicated post-depositional processes. This means that a good knowledge of pore types is vital in determining carbonate formation's elastic and reservoir properties. This study aims to develop a multi-physics approach to determine pore-type variations in a carbonate reservoir using well log information from one of the oilfields of the Abadan Plain in southwest Iran. Firstly, we determined lithology, porosity, and fluid content by interpreting conventional well logs (gamma ray, resistivity, density, neutron, photoelectric, and P-wave sonic). Then, nuclear magnetic resonance data were used to determine different pore types within the Main Ilam and Sarvak formations. We distinguished between clay, micro, meso, and macro pore types. We confirmed our interpretation results using thin sections, scanning electron microscopy photographs, and pore-size distribution on the available core plugs. Finally, a carbonate rock physics model was employed to model sonic velocities using petrophysical interpretation along with pore-type determination results. A good match between modeled and measured sonic velocities confirmed that using nuclear magnetic resonance data for pore-type determination can reasonably estimate pore-type variations needed for rock physics modeling. The standard industry procedure for carbonate rock physics modeling uses sonic logs, core data, or thin sections to determine pore types. We offer a substitute approach with reasonable accuracy for pore-type modeling needed for carbonate rock physics modeling. We modeled pore types independently from sonic velocity and used them to predict P-wave velocity with a correlation coefficient of 92 and 64 percent accuracy in the Main Ilam and Sarvak formations. [ABSTRACT FROM AUTHOR]

Copyright of Environmental & Social Management Journal / Revista de Gestão Social e Ambiental is the property of Environmental & Social Management Journal and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The discovery of huge gas plays in the deep-water geological systems (e.g., eastern Mediterranean, North America, southern Pacific, etc.), along with improving the exploration technique, have encouraged the exploration campaign to resume the exploration activities in similar contexts around the globe. As such, the onshore-offshore Taranaki Basin, which is the sole gas-bearing basin in New Zealand, has an extensive exploration campaign focused on the onshore parts of the basin, whereas the deep-water regions are still poorly explored. Among these petroleum systems, the architecture of the Palaeogene-Neogene reservoirs in the Western offshore Taranaki Basin, and the implication of depositional and diagenetic attributes on their reservoir quality are yet obscure. To address the above uncertainties, we integrate seismic-stratigraphy, well log analysis, and petrographic investigations to define the stratigraphic evolution and reservoir facies distribution, revealing the factors controlling the development of their pore systems. This petrophysical analysis reveals that, the sandstones of Farewell F have the best reservoir quality within the Palaeocene transgressive succession. Furthermore, clastic-dominated shelf conditions continued during the Eocene, where the transgressive sandstones of Kaimiro D reservoir presented the main reservoir within the Eocene succession. However, due to ineffective migration, both reservoirs are tested and considered non gas-producing. Results of this testing suggested that, upwards, a deep-water sedimentation prevailed during the Middle Miocene, resulting in the deposition of basin-floor fan lobes/sandstones of the Manganui Formation and its equivalent Moki Formation, which could host the most potential reservoir targets due to the presence of many sand lobes. Therefore, the present study recommends testing these sand lobes. Finally, our findings highlight the significance of reanalyzing and integrating seismic stratigraphy, well logging, and petrography in exploring the untapped potential reservoir zones in the Taranaki Basin that can be used globally in similar settings. [ABSTRACT FROM AUTHOR]

Tight gas reservoirs with low porosity and low permeability can encounter problems such as small dynamic range of measurement information and low log-response sensitivity, which make it difficult to accurately identify gas reservoirs and evaluate gas saturation. The purpose of this paper is to improve the accuracy of tight gas reservoirs evaluation by combining different nuclear logging methods. Slope, a parameter based on thermal neutron cross section and density, is proposed to improve the accuracy of tight gas reservoirs evaluation. The Monte Carlo method is used to analyze the sensitivity of different nuclear logging parameters to gas-bearing formations. The effects of various environmental factors on slope calculation results are analyzed. The applicability of the proposed method in synthetic models and field data is analyzed to verify its effectiveness. The results show that the sensitivity of the slope-based method to gas in low-porosity formations is much higher than that of other methods. Shale content has a minor impact on slope. Lithology and gas density affect slope calculation results. Salinity has little effect on slope in low-porosity formations. The data interpretation results from the field well show that the accuracy of gas saturation calculation of the slope-based method is much higher than that of the Archie formula-based method. The proposed method can provide strong support for the effective exploration and development of tight gas reservoirs. [ABSTRACT FROM AUTHOR]

Abstract Large-scale geological sequestration of CO2 is one of the most effective strategies to limit global warming to below 2 °C, as recommended by the Intergovernmental Panel on Climate Change (IPCC). Therefore, identifying and characterizing high-quality storage units is crucial. The Surma Basin, with its four-way dip closed structures, high-quality reservoirs, and thick regional cap rocks, is an ideal location for CO2 storage. This study focuses on the Bokabil Formation, the most prominent reservoir unit in the Surma Basin. Detailed petrographic, petrophysical, XRD, and SEM analyses, along with mapping, have been conducted to evaluate the properties of the reservoir and cap rock within this formation. The Upper Bokabil Sandstone in the Surma Basin ranges from 270 to 350 m in thickness and consists of fine- to medium-grained subarkosic sandstones composed of 70–85% quartz and 5–12% feldspar, with good pore connectivity. Petrophysical analysis of data from four gas fields indicates that this unit has a total porosity of 21–27.4% and a low shale volume of 15–27%. Cross plots and outcrop observations suggest that most of the shales are laminated within the reservoir. The regional cap rock, known as the Upper Marine Shale (UMS), ranges in thickness from 40 to 190 m and contains 10–40 nm nano-type pores. A higher proportion of ductile materials with a significant percentage of quartz in the UMS indicates higher capillary entry pressures, enhancing its capacity to hold CO2. Using the CSLF method with a 6% cut-off of the available pore volume, it is estimated that 103 Mt, 110 Mt, 205 Mt, and 164 Mt of CO2 can be effectively stored in the Sylhet, Kailashtila, Habiganj, and Fenchuganj structures, respectively. Due to the shallow depth of the storage unit and the thick cap rock, the southern Surma Basin is the optimal location for CO2 injection.

A very common hazard in Rwanda is represented by the instability of steep road cut slopes in lateritic soil. In its natural state, this material appears as a fine-grained weak and altered rock, generally in unsaturated conditions. Steep cut slopes made by this material could remain stable for a long time unless weathering weakens its mechanical behavior and heavy rainfall provokes a rapid landslide. This paper presents the results of an experimental investigation on the microstructural, petrophysical, and geotechnical properties of lateritic soil from a road cut slope located in Kabaya (Ngororero District—Rwanda), which was recently subjected to a landslide. The mechanical properties of the material are strictly related to the geological origin and history of the deposits, their formation environment, and weathering processes. These characteristics were revealed by peculiar microstructural features (micro-texture, porosity, and degree of alteration of original mineral paragenesis). The experimental investigations included identification and classification tests, direct shear tests on saturated samples, and swelling tests. This multidisciplinary approach provided insights into the relationship between geotechnical properties and the microstructural, petrophysical, and chemical characteristics of the altered rocks. This study showed how different levels of chemical alteration operated by weathering processes, in conjunction with brittle deformation related to the tectonic history, formed in the same site two shallow rock layers with similar macro-scale features and mechanical behaviors but markedly different microstructural and chemical properties. The innovative aspect of this research suggests an integrated multidisciplinary approach to considering microstructural aspects in addition to mechanical behavior in the slope stability analyses in lateritic soil. In particular, this study demonstrates the importance of such an approach since the failure mechanism is better explained if it is based on microstructural observations instead of considering the soil shear strength parameters only. This research helped to explain the formation of the landslide failure mechanism in a specific road cut slope, which could be assumed as representative of many other similar slopes subjected to landslides in Rwanda.

In this study, taking the Jurassic Lianggaoshan Formation (J1l) tight sandstones in the eastern Sichuan Basin as an example, the types and well-logging responses of main sedimentological and diagenetic facies in the lacustrine delta-front are investigated based on summarizing the sedimentary characteristics and reservoir properties. Subsequently, further validation and application are conducted in the study area through machine learning. Research results show that the J1l lacustrine delta-front in the eastern Sichuan Basin mainly develops subaqueous distributary channels and mouth bar sand bodies, exhibiting typical densification reservoirs, with porosity and permeability distributed between 0.48% and 11.24% (av. 3.87%) and 0.0003-0.653 x 10-3 µm² (av. 0.026 x 10-3 µm²), respectively. Strong compaction and strong cementation are the primary factors leading to densification, whereas chlorite coatings and weak dissolution play constructive roles in preserving some primary pores, creating a small amount of dissolution pores, and enhancing permeability. In terms of manifestation, the pore-throat content with a radius greater than 0.006 µm governs the reservoir quality. Furthermore, five types of diagenetic facies are identified in the J1l subaqueous distributary channels and mouth bars: strong compaction facies (Type I), strong cementation facies (Type II), chlorite-coating and intergranular pore facies (Type III), weak dissolution and intragranular pore facies (Type IV), and medium compaction and cementation facies (Type V). Overall, the thick and coarse-grained subaqueous distributary channels can be considered as the preferred exploration targets for tight oil and gas, with type III and type IV diagenetic facies being the most favorable reservoirs, characterized by well-logging responses of high AC and low GR, DEN, and RT. Based on the fine division of sedimentological and diagenetic facies, establishing well-logging interpretation models and then employing machine learning to achieve sweet spot reservoir prediction can provide valuable insights for tight oil and gas exploration in regions lacking core data. [ABSTRACT FROM AUTHOR]

Different observation data are utilized to obtain a unified geophysical model based on the correlations of underground geological bodies in joint inversions. By specifying a type of Gramian constraints, Gramian as a coupling term can link geophysical models through relationships of physical properties or structural similarities. Considering the complex relationships of physical properties of underground geological bodies, we proposed an adaptive zoning method to automatically divide the whole inversion area into subregions with different relationships of physical properties and to determine the number and range of subregions that utilized correlation between geophysical data before joint inversions. On this basis, we considered the use of a combination of Gramian coupling terms rather than one term to link petrophysical and structural domains during joint inversions. Synthetic tests showed that the algorithm is capable of having a robust estimate of the spatial distribution and relationships between density and magnetization intensity of geological bodies. The idea was also applied to the ore concentration area in the middle and lower reaches of the Yangtze River to obtain the three-dimensional (3-D) distribution model of magnetite-bearing rocks within 5 km underground, which corresponds well with the existing shallow ore sites and demonstrates the existence of available deep resources in the study area. [ABSTRACT FROM AUTHOR]

This study used seismic and petrophysics data to identify potential subsurface facies that are viable hydrocarbon productive areas in the southern part of the Orange basin of South Africa. Two target areas were identified as target areas 1 and 2. In Target Area 1, three facies were identified: sand, silt and shale. The sand facies has the best reservoir quality (volume of shale between 20 to 30%; porosity from 9 to 17%; permeability from 5 to 15 mD, and water saturation from 40 to 60%), while the shale facies present the lowest reservoir quality rock (volume of shale greater than 40%; porosity from 0 to 5%; permeability from 0 to 0.5 mD, and water saturation from 80 to 100%). Target Area 1 mainly consisted of silty shale and shaly silt. However, Target Area 2 had the same facies as Target Area 1, except with additional basement facies comprising well-sorted fine to medium-grain sands. Target Area 2 had considerably thicker sand layers; thus, the petrophysical properties are slightly better, with the basement facies having a volume of shale less than 20%, porosity between 20 and 23%, permeability greater than 15mD, and water saturation between 30 and 45%. The overall reservoir rock quality in the triangulated area is generally poor because of a high concentration of clay in the matrix in sandstone layers. Regarding economic potential, Target Area 2 was identified as the most productive area with better reservoir qualities due to the basement facies. The recoverable gas in Target Area 1 is 95 057 cubic metres, while area 2 has a volume of 151 923 cubic metres. This study has shown for the first time that the southern part of the Orange Basin is not economically viable. [ABSTRACT FROM AUTHOR]

To improve the signal-to-noise ratio (SNR) of nuclear magnetic resonance (NMR) echo data with SNR below 8 obtained from tight sandstone reservoirs and improve the accuracy of the porosity obtained from T 2 inversion, a novel de-noising method is developed to improve the processing of NMR echo data. The algorithm is based on variational mode decomposition wavelet threshold (VMD-WT). It was found that as the decomposition mode number increases, the center frequency difference between the first mode and the second mode gradually decreases. A method to determine a reasonable mode decomposition number based on the center frequency difference of the modes is proposed. The effectiveness of the algorithm is verified by the application in the numerical simulation experiments and actual NMR echo data, respectively. The results indicated that, compared with wavelet threshold de-noising method, VMD-WT de-noising method is more suitable for the de-noising of NMR echo data with SNR below 8 obtained from tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

Copyright of Coal Geology & Exploration is the property of Xian Research Institute of China Coal Research Institute and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Electrical measurements can be used to estimate hydraulic properties such as permeability (k) in sedimentary rocks. Previous work has focused on sandstones, siltstones, and carbonates, while investigations on mudstones have rarely been reported. In this study, we report on electrical geophysical measurements for 23 mudstone samples using an experimental approach designed to reliably saturate these low permeability mudstones. The modified Hagen‐Poiseuille model linking permeability to the formation factor (F) and an effective pore radius (r) provides an excellent fit to the data set with a near‐constant pore radius, indicating that the effective porosity (1/F) is the controlling factor on k. In these samples, the surface area normalized to pore volume (Spor), frequently used in permeability estimation models, varies by 1–2 orders of magnitude and is thus not a reliable proxy of the inverse effective hydraulic radius. The formation factor also exerts the primary control on induced polarization (IP) parameters, whereas Spor shows no relation to the IP parameters. A strong linear relationship is found between IP parameters (imaginary conductivity and normalized chargeability) and surface conductivity, although the proportionality factor is significantly lower than those observed in more permeable rocks and sediments. Apparent relationships between the polarization strength‐derived and time constant‐derived geophysical length scales and the effective hydraulic radius appear to be driven by variations in the electrochemical parameters (i.e., specific polarizability and diffusion coefficient). Overall, these findings emphasize that predicting hydraulic properties from electrical measurements in fine‐grained rocks remains challenging and requires further investigation into the electrochemical properties involved. Plain Language Summary: Permeability governs the flow of fluids, such as groundwater, and the transport of solutes in the Earth's subsurface. Quantifying the permeability of low‐permeability materials is important for nuclear waste storage, carbon sequestration, geothermal energy production, and hydrocarbon exploration. Electrical geophysical methods can non‐invasively measure properties that control permeability in the subsurface. Previous studies on loose, unconsolidated sediments and relatively permeable sandstones show how electrical properties are controlled by the physical properties describing the geometry of the interconnected pore network. However, in finer‐grained sedimentary rocks like mudstones, electrical properties are not so well reported, in part due to difficulties in acquiring accurate measurements on low permeability samples with small pores. In our study of 23 mudstone samples, we find that permeability and the electrical polarization of these samples are primarily controlled by the effective porosity (a measure of the interconnected pore space through which electrical current is channeled) with the samples represented by a near constant effective pore radius. The pore surface area per unit volume is not a good measure of effective pore radius or well correlated with electrical properties. We also find that electrical polarization is correlated with magnetic susceptibility, an indicator of iron mineral concentration. Key Points: Permeability and IP parameters are predominantly controlled by the effective porosity (1/formation factor) of mudstonesThe modified Hagen‐Poiseuille equation well predicts the permeability (k) of these mudstones, with a single effective pore radiusPore geometry descriptors (Spor) show no correlation with k or IP parameters, with IP parameters strongly controlled by effective porosity [ABSTRACT FROM AUTHOR]

Three-dimensional electron tomography was employed to carry out a thorough and quantitative analysis of the porosity in biomass tobacco and its resulting carbon materials. The findings suggest that the porosity features are largely inherited from the biomass to its resulting carbon materials, and that mesoporosity could be further increased by altering the pyrolysis temperature. [ABSTRACT FROM AUTHOR]

The carbon capture and storage (CCS) process has become one of the main technologies used for mitigating greenhouse gas emissions. The success of CCS projects relies on accurate subsurface reservoir petrophysical characterization, enabling efficient storage and captured CO 2 containment. In digital rock physics, X-ray microtomography (μ -CT) is applied to characterize reservoir rocks, allowing a more assertive analysis of physical properties such as porosity and permeability, enabling better simulations of porous media flow. Estimating petrophysical properties through numeric simulations usually requires high-resolution images, which are expensive and time-inefficient to obtain with μ -CT. To address this, we propose using two deep learning models: a super-resolution model to enhance the quality of low-resolution images and a surrogate model that acts as a substitute for numerical simulations to estimate the petrophysical property of interest. A correction process inspired by generative adversarial network (GAN) adversarial training is applied. In this approach, the super-resolution model acts as a generator, creating high-resolution images, and the surrogate network acts as a discriminator. By adjusting the generator, images that correct the errors in the surrogate's estimations are produced. The proposed method was applied to the DeePore dataset. The results shows the proposed approach improved permeability estimation overall. [ABSTRACT FROM AUTHOR]

Liquid nitrogen freezing has a certain promoting effect on improving the permeability of coal samples. In order to study the quantitative changes in the pore structure and permeability of coal samples after liquid nitrogen freezing, this paper carried out a three-dimensional reconstruction of the pore space structure of coal samples based on CT scanning experiments, and based on this, the porosity, connected pore volume, the equivalent pore radius, pore coordination number and permeability were studied based on the reconstruction model. The results show that the porosity of the coal samples in group B is 42.02% higher than that in group A after freezing with liquid nitrogen, the average value of the total connected pore volume, pore equivalent radius and coordination number of coal samples in group B are greater than those in group A, and they have increased by 16.5%, 2.95% and 14.8% respectively; the permeability in group B is 26.86% higher than that of group A, indicating that the pore connectivity and permeability of the coal samples in the liquid nitrogen freezing group have been significantly improved. [ABSTRACT FROM AUTHOR]

Permeability is an important parameter affecting shale gas development. Shale has strong heterogeneity, and the permeabilities of the shale matrices in different lithofacies vary significantly. To study the seepage ability of shale matrices, the seepage of gas in the shale matrices of different lithofacies was simulated, the permeabilities of the shale matrices of different lithofacies were calculated, and the results were corrected according to the slippage and diffusion effect of shale gas. The calculation results show that the seepage capacities of clay shale with high total organic content and siliceous shale with high total organic content are stronger than those of other shale lithofacies. Finally, based on the permeability and proportion of different lithofacies, a calculation model of the apparent permeability of a shale reservoir considering different shale lithofacies was established. The calculation model of the apparent permeability of the shale reservoir matrix overcomes the spatial limitation of conventional methods. The calculation model can not only intuitively show the control effects of different shale lithofacies on reservoir permeability, but also master the seepage capacity of shale reservoirs in the research block as a whole. The model provides a theoretical basis for the design of shale gas development programmes. [ABSTRACT FROM AUTHOR]

Large-scale geological sequestration of CO2 is one of the most effective strategies to limit global warming to below 2 °C, as recommended by the Intergovernmental Panel on Climate Change (IPCC). Therefore, identifying and characterizing high-quality storage units is crucial. The Surma Basin, with its four-way dip closed structures, high-quality reservoirs, and thick regional cap rocks, is an ideal location for CO2 storage. This study focuses on the Bokabil Formation, the most prominent reservoir unit in the Surma Basin. Detailed petrographic, petrophysical, XRD, and SEM analyses, along with mapping, have been conducted to evaluate the properties of the reservoir and cap rock within this formation. The Upper Bokabil Sandstone in the Surma Basin ranges from 270 to 350 m in thickness and consists of fine- to medium-grained subarkosic sandstones composed of 70–85% quartz and 5–12% feldspar, with good pore connectivity. Petrophysical analysis of data from four gas fields indicates that this unit has a total porosity of 21–27.4% and a low shale volume of 15–27%. Cross plots and outcrop observations suggest that most of the shales are laminated within the reservoir. The regional cap rock, known as the Upper Marine Shale (UMS), ranges in thickness from 40 to 190 m and contains 10–40 nm nano-type pores. A higher proportion of ductile materials with a significant percentage of quartz in the UMS indicates higher capillary entry pressures, enhancing its capacity to hold CO2. Using the CSLF method with a 6% cut-off of the available pore volume, it is estimated that 103 Mt, 110 Mt, 205 Mt, and 164 Mt of CO2 can be effectively stored in the Sylhet, Kailashtila, Habiganj, and Fenchuganj structures, respectively. Due to the shallow depth of the storage unit and the thick cap rock, the southern Surma Basin is the optimal location for CO2 injection. [ABSTRACT FROM AUTHOR]

The eastern Ordos Basin plays an important role in China's coalbed methane (CBM) industry, boasting considerable CBM resources and pronounced reservoir heterogeneity, making it an ideal site for comparative research on deep and shallow CBM geology. In order to dissect the fundamental reasons for significant differences in production capacity between blocks and promote mutual learning from successful development experiences, this paper conducts a systematical study on the distribution characteristics of in-situ geological conditions of CBM reservoirs based on extensive well-testing data. Additionally, through coal permeability sensitivity experiments on coal samples with various Ro max values, burial depths, and initial permeabilities, this study explores the change law of permeability during the process of CBM extraction. The results indicate that as the burial depth of coal seam increases, so do the temperature, pressure, and stress. Moreover, the distribution of geothermal gradient, reservoir pressure gradient, horizontal stress gradient, and lateral pressure coefficient tends to converge with increasing burial depth, with a turning depth typically between 1,000 and 1,500 m. Coal seams below 1,500 m generally exhibit a normal-fault type stress field with normal-overpressure. In-situ permeability decreases with depth, but the permeability in deep stress relief zones can be maintained at a relatively high level. A lower initial permeability corresponds to a smaller stress sensitivity coefficient and reduced temperature sensitivity effects, resulting in slower permeability damage during CBM extraction. However, when the reservoir pressure drops to depletion pressure, the maximum damage rate of permeability increases significantly, underscoring the importance of reservoir reconstruction in deep CBM development. This study provides a theoretical basis for selecting favorable areas for CBM exploration and development, as well as for designing efficient development plans in practice. [ABSTRACT FROM AUTHOR]

The microstructure of realistic fluid–rock systems evolves to minimize the overall interfacial energy, enabling local variations in fluid geometry beyond ideal models. Consequently, the permeability–porosity relationship and fluid distribution in these systems may deviate from theoretical expectations. Here, we aimed to better understand the permeability development and fluid retention in deep-seated rocks at low fluid fractions by using a combined approach of high-resolution synchrotron radiation X-ray computed microtomography imaging of synthesized rocks and numerical permeability computation. We first synthesized quartzite using a piston-cylinder apparatus at different fluid fractions and wetting properties (wetting and non-wetting systems with dihedral angles of 52° and 61°–71°, respectively) under conditions of efficient grain growth. Although all fluids should be connected along grain edges and tubules in the homogeneous isotropic wetting fluid–rock system enabling segregation by gravitational compaction in natural settings, the fluid connectivity rapidly decreased to ~ 0 when the total fluid fraction decreased to 0.030–0.037, as the non-ideality of quartzite, including the interfacial energy anisotropy (i.e., grain faceting), became critical. In non-wetting systems, where the minimum energy fluid fraction based solely on the dihedral angle is ~ 0.015–0.035, the isolated (disconnected) fractions was 0.048–0.062. A streamline computation in the non-wetting system revealed that with decreasing total porosity, flow focusing into fewer channels maintained permeability, allowing the effective segregation of the connected fluids. These results provide insight into how non-wetting fluids segregate from rocks and exemplify the fraction of retained fluids in non-wetting systems. Thus, the findings suggest a potential way for wetting system fluids to be transported into the deep Earth's interior, and the amount of fluids dragged down to the Earth's interior could be higher than what was previously estimated. [ABSTRACT FROM AUTHOR]

Mineral dissolution and precipitation reactions occur in a variety of porous rocks due to the deviations from a geochemical equilibrium between solid matrix and flow fluid, resulting in the alteration of the petrophysical properties of rocks. A physically-based theoretical model is proposed based on fractal theory for quantitatively assessing the temporal evolution of permeability for porous rocks undergoing mineral dissolution and precipitation reactions. The proposed model is associated with pore structure parameters, such as initial porosity (ϕ 0) , the tortuosity fractal dimensions (D T , t) , the initial fractal dimension (D f , 0) , and the overall dissolution rate (α t) considering the precipitation reactions in porous rocks. The proposed model provides a better prediction of the time dependence of permeability compared with the available experimental data. The essential effects of the overall dissolution rate and pore structural parameters of porous rocks on the dimensionless time-dependent permeabilities are investigated in detail. It is found that the overall dissolution rate has obvious effects on the dimensionless time dependence of permeabilities. The present model may provide useful insights into the understanding of permeability change during mineral dissolution and precipitation reactions in porous rocks. [ABSTRACT FROM AUTHOR]

Fracture structures are important natural gas transport spaces in shale gas reservoirs, and their storage state in shale gas reservoirs seriously affects gas production and extraction efficiency. This work uses numerical modeling techniques to investigate the logging response law of the thermal and epithermal neutrons in the gas-containing fracture environment at various angles, applying neutron logging as a technical method. To increase the precision of the evaluation of the natural gas storage condition in shale gas reservoirs, the angle of the fractures' neutron logging data is analyzed. It is found that even in an environment with the same porosity of the fractures, there are significant differences in the logging results due to the different angles of the fracture alignment: 1. the neutron counts in the high-angle (70–90°) fracture environment are 2.25 times higher than in the low-angle (0–20°), but the diffusion area of the neutrons is only 10.58% of that in the low-angle (0–20°); 2. in the neutron energy spectrum, neutron counts are spreading to the high-energy region (7–13 MeV) along with the increase in the angle of the fracture, and the feature is especially prominent in the approximately vertical (60–90°) fracture environment, which is an increase of 528.12% in comparison with the counts in the approximately horizontal angle (0–30°) environment. The main reason for these differences is the variation in the volume of the fracture within the source radiation. This volumetric difference results from the variation in fracture angles (even though the fracture porosity is the same). In view of the above phenomenon, this paper proposes the concept of "effective fracture volume", which can intuitively reflect the degree of influence of fracture angle on neutron logging results. Further, based on the unique characteristics of shale gas reservoirs and neutrons, this paper provides important theoretical support for the modification of the porosity of the field operation, the evaluation of the physical characteristics of the gas endowment space, and the assessment. [ABSTRACT FROM AUTHOR]

A solid phase of natural gas hydrates can form from dissolved gas in oil during cold water injection into shallow undersaturated oil reservoirs. This creates significant risks to oil production due to potential permeability reduction and flow assurance issues. Understanding the conditions under which gas hydrates form and their impact on reservoir properties is important for optimizing oil recovery processes and ensuring the safe and efficient operation of oil reservoirs subject to waterflooding. In this work, we present two fluid displacement experiments under temperature control using Bentheimer sandstone core samples. A large diameter core sample of 3 inches in diameter and 10 inches in length was instrumented with multiphysics sensors (i.e., ultrasonic, electrical conductivity, strain, and temperature) to detect the onset of hydrate formation during cooling/injection steps. A small diameter core sample of 1.5 inches in diameter and 12 inches in length was used in a coreflooding apparatus with high-precision pressure transducers to determine the effect of hydrate formation on rock permeability. The fluid phase transition to solid hydrate phase was detected during the displacement of live-oil with injected water. The experimental procedure consisted of cooling and injection steps. Gas hydrate formation was detected from ultrasonic measurements at 7 °C, while strain measurements registered changes at 4 °C after gas hydrate concentration increased further. Ultrasonic velocities indicated the pore-filling morphology of gas hydrates, resulting in a high hydrate saturation of theoretically up to 38% and a substantial risk of intrinsic permeability reduction in the reservoir rock due to pore blockage by hydrates. [ABSTRACT FROM AUTHOR]

The Bjerkreim–Sokndal (BKS) intrusion in southern Norway has been studied for decades due to the presence of magnetic remanence creating anomalies 12 000 nT below background as measured by airborne magnetic surveys. The strong magnetic remanence also makes the BKS intrusion a good Earth analogue for remote studies of planets that have prominent magnetic signatures, such as Martian geological environments. Although numerous geophysical surveys and samples have been collected in the area, there are limited 3-D geological interpretations of the subsurface. Here, we used existing geophysical data to conduct forward and inversion modelling of the Bjerkreim lobe to investigate the subsurface geometry of the BKS intrusion. An extensive petrophysical property compilation was used as input data for the models, in combination with airborne magnetics and digital elevation models. This petrophysical compilation was initially analysed using principal component analysis to understand which variables would have the greatest impact on the models. Forward and inversion modelling show that cross-cutting jotunite bodies, and small anorthosite blocks within the Bjerkreim lobe have a limited depth extent of 1 km. Massive and foliated anorthosites to the west of the Bjerkreim lobe extend to depths greater than 4 km indicating that the BKS intruded into these anorthosites. Complications in magnetic field fitting during the forward modelling of megacyclic units with strong magnetic remanence and the results from a new ground magnetic survey support the need to revisit mapped contacts of the cyclical units. [ABSTRACT FROM AUTHOR]

The complex pore structure of carbonate reservoirs hinders the correlation between porosity and permeability. In view of the sedimentation, diagenesis, testing, and production characteristics of carbonate reservoirs in the study area, combined with the current trends and advances in well log interpretation techniques for carbonate reservoirs, a log interpretation technology route of "geological information constraint þ deep learning" was developed. The principal component analysis (PCA) was employed to establish lithology identification criteria with an accuracy of 91%. The Bayesian stepwise discriminant method was used to construct a sedimentary microfacies identification method with an accuracy of 90.5%. Based on production data, the main lithologies and sedimentary microfacies of effective reservoirs were determined, and 10 petrophysical facies with effective reservoir characteristics were identified. Constrained by petrophysical facies, the mean interpretation error of porosity compared to core analysis results is 2.7%, and the ratio of interpreted permeability to core analysis is within one order of magnitude, averaging 3.6. The research results demonstrate that deep learning algorithms can uncover the correlation in carbonate reservoir well logging data. Integrating geological and production data and selecting appropriate machine learning algorithms can significantly improve the accuracy of well log interpretation for carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Interpreting reservoir properties through log data and logging responses in complex strata is critical for efficient petroleum exploitation, particularly for metamorphic rocks. However, the unsatisfactory accuracy of such interpretations in complex reservoirs has hindered their widespread application, resulting in severe inconvenience. In this study, we proposed a multi-mineral model based on the least-square method and an optimal principle to interpret the logging responses and petrophysical properties of complex hydrocarbon reservoirs. We began by selecting the main minerals based on a comprehensive analysis of log data, X-ray diffraction, petrographic thin sections and scanning electron microscopy (SEM) for three wells in the Bozhong 19-6 structural zone. In combination of the physical properties of these minerals with logging responses, we constructed the multi-mineral model, which can predict the log curves, petrophysical properties and mineral profile. The predicted and measured log data are evaluated using a weighted average error, which shows that the multi-mineral model has satisfactory prediction performance with errors below 11% in most intervals. Finally, we apply the model to a new well "x" in the Bozhong 19-6 structural zone, and the predicted logging responses match well with measured data with the weighted average error below 11.8% for most intervals. Moreover, the lithology is dominated by plagioclase, K-feldspar, and quartz as shown by the mineral profile, which correlates with the lithology of the Archean metamorphic rocks in this region. It is concluded that the multi-mineral model presented in this study provides reasonable methods for interpreting log data in complex metamorphic hydrocarbon reservoirs and could assist in efficient development in the future. [ABSTRACT FROM AUTHOR]

This research uses both three-dimensional (3D) modeling and geologic well control to piece back together the architectural parts of the Late Cretaceous formations. The goal is to figure out the sizes, directions, locations, and controls of the layers of the fluvial sandstone reservoirs. Sequence stratigraphy is essential for 3D reservoir modeling and petroleum geology understanding in the Bahga oilfield. The purpose of this work is to create a static model that shows the layers and facies distribution in the reservoir interval. We will use data from nine well logs and 22 seismic lines calibrated by the Abu Roash G Member reservoir core intervals to accomplish this. The petrophysical study discovered three parts in the Abu Roash G Member reservoir rock: channel fill that is affected by tides, channel fill that is dominated by tides (intertidal sands), and channel top with lenticular bedded sandstone. The model's findings point to the existence of an NNW-oriented sand body, which could be a prime location to produce hydrocarbons. The original oil in place (OOIP) is about 3,438,279 Stock Tank Barrels (STB), and the oil reserve reaches up to 1,031,484 (STB). Sequence stratigraphic analysis using seismic and well log information (SB) reveals that the Upper Cretaceous AR/G reservoir of the Bahga field is characterized by third- and fourth-order stratigraphic sequences, which are constrained by three Maximum Flooding Surfaces (MFS) and two Sequence Boundaries. The integration of the derived geological model and sequence stratigraphic results can lower future extraction risk by identifying the locations and trends of the geologic facies with the necessary petrophysical properties for the hydrocarbon accumulations. [ABSTRACT FROM AUTHOR]