Search Results (49)

The deep carbonate reservoirs in the Tarim Basin, Xinjiang, China, are widely developed with multi-scale complex reservoir spaces such as fractures, pores, and karst caves under the coupling of abnormal high pressure, diagenesis, karst, and tectonics and have strong heterogeneity. Among them, fracture–cavity carbonate reservoirs are one of the main reservoir types. Revealing the petrophysical characteristics of fracture–cavity carbonate reservoirs can provide a theoretical basis for the log interpretation and geophysical prediction of deep reservoirs, which holds significant implications for deep hydrocarbon exploration and production. In this study, based on the mineral composition and complex pore structure of carbonate rocks in the Tarim Basin, we comprehensively applied classical petrophysical models, including Voigt–Reuss–Hill, DEM (Differential Effective Medium), Hudson, Wood, and Gassmann, to establish a fracture–cavity petrophysical model tailored to the target block. This model effectively characterizes the complex pore structure of deep carbonate rocks and addresses the applicability limitations of conventional models in heterogeneous reservoirs. The discrepancies between the model-predicted elastic moduli, longitudinal and shear wave velocities (Vp and Vs), and laboratory measurements are within 4%, validating the model’s reliability. Petrophysical template analysis demonstrates that P-wave impedance (Ip) and the Vp/Vs ratio increase with water saturation but decrease with fracture density. A higher fracture density amplifies the fluid effect on the elastic properties of reservoir samples. The Vp/Vs ratio is more sensitive to pore fluids than to fractures, whereas Ip is more sensitive to fracture density. Regions with higher fracture and pore development exhibit greater hydrocarbon storage potential. Therefore, this petrophysical model and its quantitative templates can provide theoretical and technical support for predicting geological sweet spots in deep carbonate reservoirs. Full article

The crystallization of soluble salts is one of the most significant agents of deterioration affecting porous building materials in historical architecture. This process not only compromises the physical integrity of the materials but also results in considerable aesthetic, structural, and economic consequences. Soluble salts involved in these processes may originate from geogenic sources—including soil leachate, marine aerosols, and the natural weathering of parent rocks—or from anthropogenic factors such as air pollution, wastewater infiltration, and the use of incompatible restoration materials. This study examines the role of capillary rise as a primary mechanism responsible for the vertical migration of saline solutions from the soil profile into historic masonry structures, especially those constructed with calcareous stones. It describes how water retained or sustained within the soil matrix ascends via capillarity, carrying dissolved salts that eventually crystallize within the pore network of the stone. This phenomenon leads to a variety of damage types, ranging from superficial staining and efflorescence to more severe forms such as subflorescence, microfracturing, and progressive mass loss. By adopting a multidisciplinary approach that integrates concepts and methods from soil physics, hydrology, petrophysics, and conservation science, this paper examines the mechanisms that govern saline water movement, salt precipitation patterns, and their cumulative effects on stone durability. It highlights the influence of key variables such as soil texture and structure, matric potential, hydraulic conductivity, climatic conditions, and stone porosity on the severity and progression of deterioration. This paper also addresses regional considerations by focusing on the context of Spain, which holds one of the highest concentrations of World Heritage Sites globally and where many monuments are constructed from vulnerable calcareous materials such as fossiliferous calcarenites and marly limestones. Special attention is given to the types of salts most commonly encountered in Spanish soils—particularly chlorides and sulfates—and their thermodynamic behavior under fluctuating environmental conditions. Ultimately, this study underscores the pressing need for integrated, preventive conservation strategies. These include the implementation of drainage systems, capillary barriers, and the use of compatible materials in restoration, as well as the application of non-destructive diagnostic techniques such as electrical resistivity tomography and hyperspectral imaging. Understanding the interplay between soil moisture dynamics, salt crystallization, and material degradation is essential for safeguarding the cultural and structural value of historic buildings in the face of ongoing environmental challenges and climate variability. Full article

Understanding diagenetic processes is fundamental to characterizing heterogeneous carbonate reservoirs, where variations in pore structures and mineralogy significantly influence reservoir quality and fluid flow behavior. This study presents an integrated diagenetic classification approach applied to the upper Dalan and Kangan formations in the Persian Gulf. Utilizing extensive core analyses, petrographic studies, scanning electron microscopy (SEM) imaging, and petrophysical data, six distinct diagenetic classes were identified based on the quantification of key processes such as dolomitization, dissolution, cementation, and compaction. The results reveal that dolomitization and dissolution enhance porosity and permeability, particularly in high-energy shoal facies, while cementation and compaction tend to reduce reservoir quality. A detailed petrographic examination and rock typing, including pore type classification and hydraulic flow unit analysis using flow zone indicator methods, allowed the subdivision of the reservoir into hydraulically meaningful units with consistent petrophysical characteristics. The application of the Stratigraphic Modified Lorenz Plot facilitated large-scale reservoir zonation, revealing the complex internal architecture and significant heterogeneity controlled by depositional environments and diagenetic overprints. This diagenetic classification framework improves predictive modeling of reservoir behavior and fluid distribution, supporting the optimization of exploitation strategies in heterogeneous carbonate systems. The approach demonstrated here offers a robust template for similar carbonate reservoirs worldwide, emphasizing the importance of integrating diagenetic quantification with multi-scale petrophysical and geological data to enhance reservoir characterization and management. Full article

The growing energy demand and the need for climate mitigation strategies have spurred interest in the application of CO₂–enhanced oil recovery (CO₂–EOR) and carbon capture, utilization, and storage (CCUS). Furthermore, natural hydrogen (H₂) production and underground hydrogen storage (UHS) in geological media have emerged as promising technologies for cleaner energy and achieving net–zero emissions. However, selecting a suitable geological storage medium is complex, as it depends on the physicochemical and petrophysical characteristics of the host rock. Solubility is a key factor affecting the above–mentioned processes, and it is critical to understand phase distribution and estimating trapping capacities. This paper conducts a succinct review of predictive techniques and present novel simple and non–iterative predictive models for swift and reliable prediction of solubility behaviors in CO₂–brine and H₂–brine systems under varying conditions of pressure, temperature, and salinity (T–P–m salts), which are crucial for many geological and energy–related applications. The proposed models predict CO₂ solubility in CO₂ + H₂O and CO₂ + brine systems containing mixed salts and various single salt systems (Na⁺, K⁺, Ca²⁺, Mg²⁺, Cl⁻, SO₄²⁻) under typical geological conditions (273.15–523.15 K, 0–71 MPa), as well as H₂ solubility in H₂ + H₂O and H₂ + brine systems containing NaCl (273.15–630 K, 0–101 MPa). The proposed models are validated against experimental data, with average absolute errors for CO₂ solubility in pure water and brine ranging between 8.19 and 8.80% and for H₂ solubility in pure water and brine between 4.03 and 9.91%, respectively. These results demonstrate that the models can accurately predict solubility over a wide range of conditions while remaining computationally efficient compared to traditional models. Importantly, the proposed models can reproduce abrupt variations in phase composition during phase transitions and account for the influence of different ions on CO₂ solubility. The solubility models accurately capture the salting–out (SO) characteristics of CO₂ and H₂ gas in various types of salt systems which are consistent with previous studies. The simplified solubility models for CO₂ and H₂ presented in this study offer significant advantages over conventional approaches, including computational efficiency and accuracy across a wide range of geological conditions. The explicit, derivative–continuous nature of these models eliminates the need for iterative algorithms, making them suitable for integration into large–scale multiphase flow simulations. This work contributes to the field by offering reliable tools for modeling solubility in various subsurface energy and environmental–related applications, facilitating their application in energy transition strategies aimed at reducing carbon emissions. Full article

Organic-rich hot Qusaiba shale is the primary source rock of most of the Paleozoic hydrocarbon reservoirs of eastern and central Arabia. Representative near-surface Qusaiba shale samples were collected and characterized from one of its outcrop sections at the Tayma quadrangle in northwest Saudi Arabia. The petrophysical and geochemical characterization indicated porosity and permeability of 8.2% and 2.05 nD, respectively, with good total organic carbon (TOC) of 2.2 mg/g and mature kerogen of gas-prone type III. The tight characteristics of the formation can lead to high capillary pressure and extensive post-fracking water retention, leading to flow blockage and a reduction in gas productivity. Three different surfactants and one ionic liquid, namely, Triton X-100, Triton X-405 and Zonyle FSO surfactants and Ammoeng 102 ionic liquid, were tested as additives to fracking fluid to investigate their effectiveness in optimizing its performance. The chemical solutions exhibited no sign of instability when exposed to solution salinity and temperatures up to 70 °C. The investigated chemicals’ performance was examined by measuring methane/chemical solutions’ surface tension and their ability to alter shale’s wettability. The results indicate that Zonyl FSO is the most effective chemical, as it is able to significantly reduce surface tension and, hence, capillary pressure by 66% when added at critical micelle concentration (CMC). Using Zonyl FSO surfactant at a maximum tested concentration of 0.2% induced a relatively smaller capillary pressure drop (54%) due to the drastic drop in the contact angle rendering shale very strongly water-wet. Such a drop in capillary pressure can lower the fracking fluid invasion depth and therefore ease the liquid blockage removal during the flowback stage, enhancing gas recovery during the extended production stage. Triton X-100 at CMC was the second most effective surfactant and was able to induce a quite significant 47% drop in capillary pressure when added at the maximum tested concentration of 0.05%. This was sufficient to remove any liquid blockage but was less likely to alter the wettability of the shale. Based on the findings obtained, it is suggested to reduce the blockage tendency during the fracking process and elevate any existing blockage during the flowback stage by using Zonyl FSO at CMC where IFT is at its minimum with a higher contact angle. Full article

Fluid components in cores are crucial parameters in evaluating the quality of a shale reservoir in both laboratory analyses and log interpretation. In the Gulong area, shale reservoirs are characterized by a high clay content, with clay spaces hosting both oil and water phases, complicating the occurrence mechanism of fluid components, as a result, traditional research methods are no longer applicable. As an advanced technique, nuclear magnetic resonance (NMR) has been applied in oilfields to determine the specific petrophysical properties of rocks. To more accurately identify the types of fluid components, this study carried out a new, well-designed 2D NMR experiment, rock pyrolysis experiment, and quantitative oil and water detection experiment (QOWDE) to study the Gulong shale. This study measured the 2D NMR map of the original state, saturation state, centrifugal state, and pyrolysis at different temperatures, and conducted mutual verification between the QOWDE and 2D NMR pyrolysis experiments to obtain the distribution of different components of Gulong shale on the 2D NMR map. Based on the experimental results, this study developed a component identification template suitable for the Gulong area and calculated the 2D NMR porosity and saturation from it. This lays a foundation for the analysis and application of fluid components in the Gulong region and provides a new experimental basis and methodological support for porosity and saturation calculations. Full article

Non-invasive techniques, such as close-range photogrammetry (CRP) and 3D ultrasonic tomography complemented with optical and scanning electron microscopy and mercury porosimetry, were applied to characterize the carbonate rock samples of the Calcari di Cagliari formation. The integrated approach started with the computation of high-resolution 3D models of the carbonate samples using the CRP technique to produce 3D high-resolution models texturized both with natural colors and intensity. Starting from the 3D models from previous techniques, a 3D ultrasonic tomography on each rock sample was accurately planned and carried out in order to detect the elastic properties of such rocks and relate them to textural heterogeneity or internal defects. The results indicate that the relationship between longitudinal velocity and rock properties is complex even in the same carbonate formation. Understanding the relationship between the geomatic and geophysical responses in the investigated rock properties, such as textural characteristics and especially structure and geometry of pores, type of pores, tortuosity and cementing material, is important for many practical applications and especially in the diagnostic process of the conservation state of monumental structures. The integration of the above non-invasive techniques complemented by petrographical–petrophysical data proved to be a powerful method to associate each lithotype with a different susceptibility to degradation. The results presented in this paper demonstrate that the proposed integrated use of complementary methodologies would guarantee the reproducibility of the measurements both at the laboratory and field scale for the monitoring in time of the rock condition while giving a useful contribution in making decisions on an appropriate remedial strategy. Full article

The microscopic pore structure of tight sandstone reservoirs significantly influences the characteristics of CO₂ flooding after water flooding. This research was conducted using various techniques such as casting thin sections, high-pressure mercury injection, scanning electron microscopy, nuclear magnetic resonance (NMR) testing, and a self-designed high-temperature and high-pressure microscopic visualization displacement system. Three types of cores with different pore structures were selected for the flooding experiments and the microscopic visualization displacement experiments, including CO₂ immiscible flooding, near-miscible flooding, and miscible flooding after conventional water flooding. The characteristics of CO₂ flooding and the residual oil distribution after water flooding were quantitatively analyzed and evaluated. The results show the following: (1) During the water flooding process, the oil produced from type I and type III samples mainly comes from large and some medium pores. Oil utilization of all pores is significant for type II samples. The physical properties and pore types have a greater impact on water flooding. Type I and II samples are more suitable for near-miscible flooding after water flooding. Type III samples are more suitable for miscible flooding after water flooding. (2) In CO₂ flooding, oil recovery increases gradually with increasing pressure for all three types of samples. Type II core samples have the highest recovery. Before miscibility, the oil recovered from type I and type II samples is primarily from large pores; however, oil recovery mainly comes from medium pores when reaching miscibility. As for the type III samples, the oil produced in the immiscible state mainly comes from large and medium pores, and the enhanced oil recovery mainly comes from medium and small pores after reaching the near-miscible phase. (3) It can be seen from the microscopic residual oil distribution that oil recovery will increase as the petrophysical properties of the rock model improve. The oil recovery rate of near-miscible flooding after water flooding using the type II model is up to 68.11%. The oil recovery of miscible flooding after water flooding with the type III model is the highest at 74.57%. With increasing pressure, the proportion of flake residual oil gradually decreases, while the proportion of droplet-like and film-like residual oil gradually increases. Type II samples have a relatively large percentage of reticulated residual oil in the near-miscible stage. Full article

Addressing the poor performance of existing logging saturation models in low-permeability tight sandstone reservoirs and the challenges in determining model parameters, this study investigates the pore structure and fluid occurrence state of such reservoirs through petrophysical experiments and digital rock visualization simulations. The aim is to uncover new insights into fluid occurrence state and electrical conduction properties and subsequently develop a low-permeability tight sandstone reservoir saturation model with easily determinable parameters. This model is suitable for practical oilfield exploration and development applications with high evaluation accuracy. The research findings reveal that such reservoirs comprise three types of formation water: strongly bound water, weakly bound water, and free water. These types are found in non-connected micropores, poorly connected mesopores where fluid flow occurs when the pressure differential exceeds the critical value, and well-connected macropores. Furthermore, the three types of formation water demonstrate variations in their electrical conduction contributions. By inversely solving rock electrical experiment data, it was determined that for a single sample, the overall cementation index is the highest, followed by the cementation index of pore throats containing strongly bound water, and the lowest for the pore throats with free water. Building on the aforementioned insights, this study develops a parallel electrical pore cementation index term, ϕ^m′, to account for the differences among the three types of water and introduces a parallel electrical saturation model suitable for logging evaluation of low-permeability tight oil and gas reservoirs. This model demonstrated positive application effects in the logging evaluation of low-permeability tight gas reservoirs in a specific basin in the Chinese offshore area, thereby confirming the advantages of its application. Full article

Energy, gases, and solids in underground sites are stored in mining excavations, natural caverns, salt caverns, and in the pore spaces of rock formations. Aquifer formations are mainly isolated aquifers with significant spreading, permeability, and thickness, possessing highly mineralized non-potable waters. This study discusses the most important aspects that determine the storage of natural gas, hydrogen, or carbon dioxide in deep aquifers. In particular, the selection and characterization of the structure chosen for underground storage, the storage capacity, and the safety of the process are considered. The choice of underground sites is made on the basis of the following factors and criteria: geological, technical, economic, environmental, social, political, or administrative–legal. The geological and dynamic model of the storage site is then drawn based on the characteristics of the structure. Another important factor in choosing a structure for the storage of natural gas, hydrogen, or carbon dioxide is its capacity. In addition to the type and dimensions of the structure and the petrophysical parameters of the reservoir rock, the storage capacity is influenced by the properties of the stored gases and the operating parameters of the storage facility. Underground gas storage is a process fraught with natural and technical hazards. Therefore, the geological integrity of the structure under consideration should be documented and verified. This article also presents an analysis of the location and the basic parameters of gas storage and carbon dioxide storage facilities currently operating in underground aquifers. To date, there have been no successful attempts to store hydrogen under analogous conditions. This is mainly due to the parameters of this gas, which are associated with high requirements for its storage. Full article

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the east half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. The use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and uncontrolled injected fresh water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the east half of the reservoir. A detailed understanding of the mechanistic factors of inefficient waterflood operation will provide adequate insights into the development of the improved recovery technique for the field. Full article

An accurate petrophysical model of the subsurface is essential for resource development and CO₂ sequestration. We present a new workflow that provides a high-resolution estimate of petrophysical reservoir properties using seismic data with rock physics modeling and machine-learning techniques (i.e., deep learning neural networks). First, we compare the sequential prediction of the following petrophysical attributes: mineralogy, porosity, and fluid saturation, with the simultaneous prediction of all of the properties using the Volve field in the Norwegian North Sea as an example. The workflow shows that the sequential prediction produces a more efficient and accurate classification of petrophysical properties (the RMS error between the predicted and the original seismic trace is 50% smaller for the sequential compared to the simultaneous procedure). Next, the seismic amplitude response of the reservoirs was studied using rock physics modeling and amplitude versus offset (AVO) analysis to distinguish the different lithologies and fluid types. To ascertain the optimal hydrocarbon production areas, we performed Bayesian seismic inversion and applied machine learning to estimate the petrophysical properties. We examined how porosity, V_clay, and fluid variations affect the elastic properties. In Poisson’s ratio versus the P-wave impedance domain, a 10% porosity increase decreases the acoustic impedance (AI) by 30%, while a 20% V_clay decrease increases the AI by 12%. The Utsira Formation in the Volve field (5 km north of the Sleipner Øst field) was evaluated as a potential CO₂ geological storage unit using Gassmann fluid substitution and seismic modeling. We look to assess the elastic property variation caused by CO₂ saturation changes for monitoring purposes and simulate the effect. In the first 10% CO₂ substitution, the P-wave velocity decrease is 12%, a subtle effect is observed for higher CO₂ saturation values, and S-wave velocity (V_s) increases with CO₂ saturation. Our analysis aspires to assist future reservoir studies and CO₂ sequestration in similar fields. Full article

This article presents the results of petrophysical analyses of limestones and sandstones used for the construction of the wall structures of a Roman rural settlement located in Podšilo Bay on Rab Island (Croatia). An on-site analysis of the walls indicated the use of different lithotypes, which is an uncommon case in the area. So far, no petrophysical properties of the applied materials have been tested, and their provenance has not been specified. The aim of this research was to determine their usability as construction materials in an attempt to determine the possible reasons behind the usage of multiple lithotypes and their suitability as building materials. The following procedure was used to address these issues: (1) determination of the petrographic characteristics of the rocks, (2) performance of tests to characterise the mechanical properties in a complex stress state of uniaxial tension followed by uniaxial and triaxial compression, and, finally, (3) determination of the internal structure of the rocks using methods based on X-ray imaging. Multi-proxy characteristics of the materials including numerous observations and methods were performed: optical microscopy used to characterise rock petrography and mineralogy, scanning electron microscopy (SEM) coupled with EDS, as well as grinding tests; furthermore, mechanical properties were determined on cylindrical samples in accordance with European standards. X-ray microtomography using the XμCT method enabled microscopic observations and determination of the orientation of discontinuities and the rock structure. The performed analyses allowed us to distinguish three lithological types of sandstone and two types of limestone among the examined stone blocks. Stone blocks of fine- and medium-grained sandstone with carbonate binders, as well as sparitic limestone and mudstone with calcite veins, were used to build the studied structures. The analysed blocks showed traces of partial edge processing. Despite the defects in the material structure identified using XμCT, all the types of rock were characterised by high or very high strength. High values of longitudinal wave velocity confirmed the good quality of the material. These results contribute to a better understanding of the construction process and the related technological choices, and they provide the first dataset which can be used for the reconstruction of the building’s original appearance in the future. Full article

Due to the complex nature of the pore system and the diversity of pore types, carbonate rocks pose a challenge in terms of their spatial characterization. Unlike sandstones, permeability in carbonates is often not correlated conclusively with porosity. A methodology for preliminary qualitative spatial characterization of reservoirs in carbonate rocks is presented in this article, with a focus on interparametric relationships. It endeavors to apply this methodology to a reservoir situated within the Main Dolomite formation in the Polish Lowlands. Fundamental analyses rely on data plotted within rock physics templates (RPT), specifically, cross-plots of acoustic impedance as a function of the product of compressional and shear wave velocities in well log profiles. The analysis of interparametric relationships was conducted on well log profiles and subsequently integrated with seismic data using neural network techniques. Areas with the greatest potential for hydrocarbon accumulation and areas potentially exhibiting enhanced reservoir properties were identified based on the outcomes of the well log profile analysis and parametric models. The qualitative assessment of the reservoir, rooted in interparametric dependencies encompassing lithofacies characteristics and elastic and petrophysical parameters, together with reservoir fluid saturation, forms the basis for further, more detailed reservoir analysis, potentially focusing on fracture modeling. Full article

Siliceous minerals of the Dengying Formation in the Gaoshiti–Moxi area in the central Sichuan Basin exhibit four types of quartz crystals (cryptocrystalline quartz, chalcedony, microcrystalline quartz, and megacrystalline quartz) and three structural types: cryptocrystalline, microcrystalline, and mosaic (laminated mosaic, window-hole interrupted mosaic, and arc-laminated mosaic). Siliceous minerals have a great influence on the storage performance of the reservoirs in the Dengying Formation. According to the petrophysical parameters of the Dengying Formation and porosity intersection diagrams, the siliceous dolomite and the reservoirs have low impedance characteristics, which makes it difficult to distinguish between them and leads to difficulties in the characterization and prediction of the reservoirs. The transverse wave velocity is favorable for reservoir characterization. Currently, the main method used to estimate the transverse wave velocity is petrophysical modeling, which establishes a relationship between the elastic and physical parameters of the reservoir. In this paper, the siliceous minerals in the dolomite in the study area are regarded as solid inclusions, and the calculation method of the rock matrix modulus is improved by using solid replacement. Then, an improved petrophysical model is constructed by combining the KT (Kuster–Toksöz) model, the DEM (Discrete Element Method) model, the Gassmann equation, and the Wood equation. The transverse wave velocity is estimated using the improved model under the constraint of the longitudinal wave velocity. The shapes of the transverse wave velocity curves obtained by the improved model and the deviations from the measured velocities are significantly better than those of the Xu–Payne model and other models. The results show that the improved model can effectively estimate the transverse wave velocity of the reservoir in this area, which provides a basis for future reservoir predictions in this area. Full article