Caprock sealing mechanismscritically influence hydrocarbon accumulation.Gas capillary sealing, a specialized type, occurs in seals of interbeddedcoarse-fine sediments. Free gas accumulating in coarse-grained porethroats forms a microscopic “gas cap”, preventing upwardmigration of hydrocarbons from the underlying strata. Though recognizedhistorically, prior studies overlooked the impact of formation poregas. Experimental evidence confirms gas significantly enhances sealingefficiency. Sediment size contrast is essential: gas accumulationat coarse-fine interfaces strengthens sealing. This mechanism is documentedglobally, including the Anadarko Basin, ODP Site 975, and JunggarBasin. In the Penyijingxi sag periphery in Junggar Basin, conventionalseals are suboptimal. The lithology is predominantly characterizedby sand-mud interbeds. The direct cap rocks are widely distributedacross multiple stratigraphic horizons, yet overpressure exists withreduced hydrocarbon dissipation postgas charging. Thus, gas capillarysealing is identified as the primary caprock mechanism here. It accountsfor gas accumulation despite poor seals, advancing the understandingof sealing mechanisms in Junggar Basin.

Stacking types and quantitative gas-trapping evaluation of coalbed methane cap rocks in the Shanxi Coalfield.

To achieve a carbon-free economy in the medium term, hydrogen (H 2 ) has been proposed as a viable solution. This requires large-scale subsurface storage options, especially if green H 2 produced from fluctuating renewable energy sources like wind and solar energy is considered. While H 2 has already been stored successfully in salt caverns for decades, H 2 storage in porous media like hydrocarbon-depleted reservoirs and saline aquifers still requires further research. We use an almost depleted gas reservoir in northwestern Germany to test for given injection/withdrawal cycles various H 2 storage scenarios regarding different cushion gases (CG). The case study field represents a faulted reservoir in a highly fractured rock of Upper Permian (Zechstein) age, consisting mainly of dolomite as reservoir rock and anhydrite as cap rock. A dynamic reservoir model for the time span from 1959 to 2023 and history-matched using the comprehensive calibration data available for the production phase provides the basis for hypothetical seasonal H 2 storage, intending to store around 300 MMsm 3 using an isothermal compositional reservoir simulator (E300) with seven components. Nine prediction cases were simulated. Following the same injection/withdrawal cycles, the cases vary regarding the composition of the CG injected: N 2 +CH 4 , H 2 +N 2 , H 2 +CH 4 , H 2 +CO 2 , pure CH 4 , pure CO 2 , pure N 2 , and pure H 2, and the ninth scenario was done with the same conditions as one of the cases but with a further prediction of 16 years. The detailed parameter input modifications from each case will be depicted in Chapter 3. The first eight scenarios follow a 10-year prediction model (2 injection cycles and 8 withdrawals) based on the results of all eight simulations, at least on the first 4 cycles, less H 2 is recovered, except if pure H 2 is injected from the beginning as a buildup phase. Despite this, all simulations show a higher H 2 recovery for the last cycle (8th withdrawal), from 96% (pure N 2 as CG) to 99% (pure H 2 as CG). The techno-economic results, ignoring at the moment separation costs, show a variance on the Levelized Cost of Hydrogen Storage (LCHS) from 1.78 $/kg to 2.39 $/kg depending on the CG applied. CG plays a significant role in the Total Capitalized Cost (TCC). Thereon, we intend to search for the optimal CG to be applied and economically feasible. • H 2 storage in depleted carbonate reservoirs from the Zechstein in northwestern Germany with dual porosity and permeability. • Use of isothermal compositional reservoir simulator (E300) to test cushion gases (CG) like N 2 , CH 4 , and CO 2 with diffusion. • Levelized Cost of Hydrogen Storage (LCHS) varies from 1.78 $/kg to 2.39 $/kg based on CG choice. • Certain CGs and mixtures achieve both high H 2 recovery and heating values, suggesting cost-effective applications.

Novel semi-analytical model for estimating unconfined compressive strength in sandstone reservoirs: Implications for CO₂ sequestration

The Middle Cambrian salt–anhydrite succession in the Tarim Basin has been regarded as an effective regional cap-rock. However, numerous Ordovician hydrocarbon reservoirs have been discovered above the anhydrite, and recent drilling has identified industrial oil and gas flows beneath anhydrite-bearing intervals. These findings call into question the sealing effectiveness of anhydrite rocks in deep subsalt settings. In this study, X-ray diffraction (XRD), petrographic analysis, scanning electron microscopy (SEM), and triaxial compression tests were conducted to investigate the mineral composition, deformation behavior, and failure mechanisms of anhydrite rocks. The results indicate that: (1) dolomite-bearing anhydrite undergoes plastic deformation at depths greater than 4400~4600 m (~70 MPa confining pressure), whereas dolomitic anhydrite enters the plastic deformation regime below 5200~5400 m (~80 MPa confining pressure); (2) the deformation evolution of the cap rocks can be divided into four stages. Stages I–III are dominated by brittle deformation, with plasticity progressively increasing with confining pressure, whereas Stage IV is characterized by pervasive plastic deformation and strong sealing capacity, representing an effective cap rock during the critical period of hydrocarbon accumulation; (3) Middle Cambrian reservoirs in the eastern Tazhong area were destroyed by reverse faults that cut through brittle Middle Cambrian cap rocks. In contrast, Lower Cambrian gas reservoirs were charged during the Himalayan period, when the cap rocks remained intact, and exhibited strong sealing capacity. This study demonstrates the temporal variability in the sealing effectiveness of Middle Cambrian anhydrite cap rocks in the eastern Tazhong area and provides a methodological basis for deep and ultra-deep subsalt hydrocarbon exploration.

Reservoirs of interests for resource exploration, including geothermal and hydrocarbon reservoirs, commonly have an impermeable cap, which traps fluids below. Identifying this boundary is important for resource development. The cap rock for hydrocarbon reservoirs in southwest Iran contains evaporites and thus some geophysical exploration methods, specifically seismic reflection, have faced problems recovering subsurface information in this environment. As an alternative, we generate an electrical resistivity model from magnetotelluric (MT) data. Furthermore, we consider three-dimensional triaxial electrical anisotropy, which is rarely done. The study objectives are to a) define and map the boundary between the cap rock and the principal reservoir, b) characterize geological and tectonic formations in the area, and c) analyze the tectonic factors influencing the evolution of the region. A total of 359 MT measurements were acquired across the Sarab field in an array consisting of five profiles separated by >2000 m with a measurement spacing of >200 m. Transient electromagnetic (TEM) measurements were co-located with the MT measurements at 181 locations and used to correct for static shifts. Isotropic and anisotropic inversions of the MT data were performed, using all impedance tensor elements. The anisotropic electrical resistivity model exhibits both a significantly better alignment with the depths of geological formations known from drilling data and a better fit to the data. Therefore, the boundary between the primary cap rock and principal reservoir, the Gachsaran and Asmari formations, is defined and mapped across the survey area. In addition, major tectonic and fault-related features in the region are identified. • 3D resistivity model images subsurface structure and tectonic/stratigraphic features. • Boundary between cap rock and reservoir formation was characterized. • Accounting for anisotropic electrical resistivity allowed model to match drill data. • Insights into reservoir geometry and regional tectonic evolution of Sarab field, Iran.

To define flow units in sedimentary sequences it is equally important to not only identify reservoir rocks that accommodate free flowing fluids, but also to recognise cap rocks that act as barriers to fluid movement. The recognition of good reservoirs and effective seals is critical not only for conventional and unconventional petroleum reservoirs, but also in prospective areas for subsurface capture and storage. This presentation focuses on the association between bulk rock inorganic geochemical ICP-OES-MS (elemental) data acquired on cuttings and core, and the relationship between flow units in porous reservoir sediments and their accompanying cap rocks. The study utilises the open file (NOPIMS) data available from the Archer Formation reservoirs (including the Caley Sandstone) in the Bedout JV Dorado Field wells, located in the Roebuck Basin on the Northwest Shelf. Using conventional log data, core analyses and elemental data, a free fluid model is developed over sections of reservoir and cap rock to establish zones of very good, good, moderate, poor, and very poor flow. A statistical approach is employed to establish elemental associations for discrete flow zones. The advantage of this workflow is that when a model has been defined for a field or basin, the acquisition of elemental data acquired during drilling can be used as a screening tool for both reservoir and cap rock identification. The elemental data can potentially be used to identify pressure ramp ups in overburden sediments.

The Xinding Basin is located in the high-heat-flow geothermal anomaly zone in the north-central part of China. Revealing the geothermal origin mechanism of the basin is of great significance for filling the measurement gap in heat flow values in China and providing a scientific basis for the evaluation and utilization of regional geothermal resources. Based on the hydrogeochemical characteristics of thermal reservoirs and borehole data in the Xinding Basin, this paper analyzes water–rock interaction process between geothermal water and heat reservoirs and discusses the types of geothermal systems in the basin. The results indicate that the fault structures in the basin are well-developed. The hydrochemical type of typical geothermal fields is dominated by the Cl·SO4-Na type. Geothermal water is mainly immature water and receives recharge from shallow cold water with relatively rapid circulation. The discovered magma intrusion residues in the basin indicate that sections of the upper mantle with a shallow burial depth serve as the dynamic heat sources for regional thermal reservoirs. Intense extensional stretching in the Cenozoic Era resulted in high terrestrial heat flow values and an upward arching phenomenon of the Curie isothermal surface in the basin. Neotectonic movement is active in the basin. The regional geothermal reservoirs in the Xinding Basin occur in the glutenite beds of the Cenozoic Erathem and the rock formations of the New Archaean Erathem. The thick-layered Cenozoic loose sediments serve as the thermal cap rocks in this area. An efficient heat-convergent geothermal system integrating a heat source, heat channel, thermal reservoir, and cap rock (the “four-in-one” system) has promoted the formation of geothermal resources in the Xinding Basin.

The Jaboi geothermal field, located on Weh Island in western Indonesia, has a potential output of approximately 55 MWe. Previous geophysical surveys have not sufficiently identified the components of the geothermal system. The success of drilling in identifying a geothermal system depends heavily on the accuracy of the conceptual model. Consequently, developing a more precise subsurface model is crucial to minimizing drilling failures. This study aims to map the resistivity structure of the Jaboi geothermal field using the magnetotelluric method. In our research, we used 16 magnetotelluric sites that recorded data for 7 to 8 h. We successfully estimated the cap rock area with resistivity < 10 Ωm distributed across Jaboi Volcano to depths of 500 m and identified an intense resistive anomaly starting at depths of 1–2 km with resistivity > 5000 Ωm. This anomaly is probably due to a block of crystalline basement being uplifted by upwelling magmatic intrusions. The reservoir zone was estimated to be located directly below the cap rock area. The resistivity structure also reveals a fluid pathway zone in the upflow and outflow zone that connects the reservoir to the surface manifestations influenced by the Ceunohot Fault and Jaboi Fault. The resistivity structure confirmed the boundary of the Jaboi geothermal system along the coastline and in the southeastern part. This study successfully identifies key components of geothermal systems, including cap rock, reservoir zones, and fluid migration pathways.

Fast elemental analysis in the wellsite is crucial acrossthe energysector, where timely and accurate geological information drives operationalefficiency and safety. In geothermal projects, rapid geochemical characterizationaids in identifying reservoir quality and alteration zones, optimizingdrilling locations, and reducing nonproductive time. For carbon storage,a quick assessment of rock mineralogy ensures suitable cap rock integrity,which is essential for environmental safety. In hydrocarbon explorationand production, immediate elemental data enable real-time lithologyevaluation, improving well placement, reducing drilling risks, andlowering operational costs. Overall, integrating advanced machinelearning with portable, on-site Laser-Induced Breakdown Spectroscopy(LIBS) technology provides fast, reliable elemental data that supportadaptive and cost-effective resource development in these criticaloperations. In retrospect, this paper explores and evaluates the applicationand coupling of the Bayesian optimization process for hyperparametertuning with support vector machine, with the objective of quantifyingmajor oxide elements present in rock cuttings samples from LIBS. Themain objective of using this process is to automatically optimizethe model performance while minimizing the manual iterative and randomtrial and testing of the hyperparameters. In this investigation, over1000 samples were prepared to develop the predictive model, whereX-ray fluorescence was used as the reference method for obtainingconcentration. The model performance was evaluated using multiplemetrics, achieving an R-squared value in the rangeof 0.93 to 0.97, indicating the model’s reliability and accuracywhen dealing with high-dimensionality and nonlinearity that are exhibitedin the data set.

Highlights: • A novel workflow integrates multiphase flow and geomechanical models to determine site-specific CO₂ injection pressure limits. • Injection rates of up to 1.7 Mt CO₂/year per well are sustainable under reservoir constraints, with higher rates achievable due to a 10 MPa increase in pressure governed by the cap rock’s tensile strength. • Vertical wells exhibit an injection limit of ∼18 MPa/km, while horizontal configurations extend this to ∼20 MPa/km, highlighting the influence of well geometry on injection strategy design. • At the investigated storage site, overpressure in the reservoir and cap rock remains compressive over a 100-year period, confirming robust containment and long-term storage integrity. Abstract Geological carbon capture and storage (CCS) in saline formations is seen as a plausible short-term solution to reduce atmospheric carbon dioxide (CO₂) concentrations and mitigate climate change. Besides storage capacity, largely determined by pore space within a geological trap, the maximum allowable pressure in the storage formation represents a major limitation for geological CO₂ storage. This study, therefore, addresses the hydromechanical aspects of geological CO₂ storage by developing an integrated workflow to determine site-specific injection pressure limits and applying it to a potential storage site in the German North Sea sector. The workflow ensures consistency between reservoir flow and geomechanical models by automatically extracting near-wellbore geomechanical domains from the large-scale model. For a vertical well, the site-specific injection pressure limit is estimated at 17.9 MPa/km, governed by tensile failure in the storage formation. Within the cap rock, the limit increases to 28.6 MPa/km, providing a large margin of safety and enabling higher injection rates. A horizontal well configuration yields a slightly higher limit of 19.7 MPa/km, due to the larger well-reservoir contact area and improved pressure dissipation. The derived pressure limits are subsequently implemented in a large-scale dynamic simulation to verify workflow performance and assess formation integrity. Results indicate that injection rates of approximately 1.7 Mt CO₂ per year per vertical well can be sustained over 30 years, with reservoir overpressure and the corresponding stress states strongly dependent on the hydraulic setting of the reservoir. Importantly, injection-induced stresses and thus the probability of fracture formation decreases rapidly after CO₂ injection ends.

Indonesia is a country that has abundant geothermal resources. The purpose of this research is to investigate the geothermal system in the Lainea non-volcanic geothermal field, Southeast Sulawesi Province, Indonesia. This includes (i) estimating the geothermal reservoir basins, cap rocks, and basements; (ii) estimating the heat source; and (iii) evaluating the subsurface faults. The first two objectives were achieved by using the improved structural gravity inversion. The third objective was achieved by using advanced processing techniques, namely 3-D Euler deconvolution, tilt angle of horizontal gradient (TAHG), and fast sigmoid edge detection (FSED). Inversion of gravity data exhibits the reservoir basins that are located at depths from 600 m to 900 m with a density range of 2865 ≤ ρ < 2942 kg/m³. Several rock blocks with densities ranging from 2608 to 2865 kg/m³ function as caprock. The caprock is located at depths ranging from several tens of meters to 1000 m. The basement underlying the reservoir rock is the integration of rock layers with densities of 2948 ≤ ρ < 3045 kg/m³ and 3046 ≤ ρ ≤ 3122 kg/m³. The upper boundary of the basement is located at a depth of several ten meters to 1500 m below sea level. Intrusive plutonic rocks with maximum density of 3174 kg/m³ are located at depths ranging from 1500 m to more than 3000 m. The TAHG and FSED demonstrate the presence of subsurface faults with northwest-southeast and southwest-northeast trends. Euler deconvolution results support the fault model of the TAHG and FSED.

This study aims to identify the subsurface structure of the geothermal system in the Pacitan area, East Java, using gravity methods based on GGMPlus data. The analysis procedures include terrain correction to obtain the Complete Bouguer Anomaly (CBA), separation of regional and local anomalies through upward continuation, as well as two-dimensional (2D) modeling and Second Vertical Derivative (SVD) analysis to identify fault structure. The CBA values in the study area range from 107 to 115.5 mGal, where high anomalies correlate with volcanic breccia rocks and highlands, while low anomalies indicate the presence of sandstone in lowland areas. Geothermal manifestations in the form of hot springs exhibit gravity anomalies of approximately 110.5–111.5 mGal and are situated in the north of the fault in a northwest–southeast direction. The 2D modeling results reveal the presence of reservoir rocks consisting of sandstone and clay with densities ranging from 1.79 to 2.20 g/cm³, and lava rocks with densities of 2.80–2.90 g/cm³ acting as cap rocks. SVD analysis indicates the existence of a normal fault directly associated with geothermal fluid pathways. This study demonstrates that the GGMPlus gravity method is effective for preliminary exploration of geothermal systems in potential areas such as Pacitan.

ABSTRACT Shale, as a unique rock type that combines hydrocarbon generation, storage, and cap rock functions, plays a crucial role in the development of unconventional oil and gas resources. Due to its highly heterogeneous mechanical properties, the engineering issues it poses are complex and variable, making a thorough analysis of its mechanical characteristics essential. This study conducted uniaxial compression tests and Brazier tensile tests on Daqing shale oil formations. Based on experimental results, a shale discrete element numerical model was constructed using the PFC code. By simulating shale samples under different bedding models and verifying the results against experiments, the micro-mechanical parameters were calibrated. Based on this, a numerical model of wellbore instability under shale bedding characteristics was developed. The results indicate that bedding strength, dip angle, and in-situ stress characteristics are the primary controlling factors leading to shale mechanical instability. The depth of bedding instability propagation increases as bedding strength decreases and in-situ stress increases; the area of wellbore fracture exhibits a characteristic of first decreasing and then increasing with changes in bedding dip angle. These research findings provide insights into the mechanisms of wellbore instability in bedded shale formations and offer guidance for optimizing drilling designs in the field.

The Mishrif Formation, deposited in the Upper Cretaceous, is one of the important carbonate reservoirs in the southern Iraq oil fields. The petrophysical properties of the Mishrif Formation in the South Rumaila oil field were studied based on open-hole geophysical well logs of twelve wells: Caliper, gamma ray, spontaneous potential, neutron, density, resistivity, and sonic log. The calculated petrophysical properties showed that the Mishrif Formation is divided into three reservoir units, mA, mB1, and mB2 separated by cap rocks CR1 and CR2; the mB2 reservoir unit can be accounted for as having the best reservoir properties because of its high effective porosity, high oil saturation, and very low shale volume. The relationship between gamma ray and density logs gave the lithology, which suggests that the mB2 unit consists of limestone, argillaceous limestone, and a very small percentage of shale. In addition, four distinctive rock types: Poor ( shale cap rock), moderate reservoir (compacted limestone), good reservoir, and very good reservoir were identified in the Mishrif reservoir, and they are distributed throughout the reservoir’s units. The relationships between the geophysical logs to correlate the rock type pointed out that the dominant ones are second and third, which indicates that the formation has moderate to good petrophysical properties.

Offshore saline aquifer CO2 sequestration relies heavily on the sealing integrity and mechanical stability of mudstone caprocks, yet their responses to supercritical CO2 (scCO2) remain inadequately constrained for marine geological settings. Here, we integrate permeability measurements, scCO2 breakthrough pressure tests, and uniaxial mechanical experiments on natural and reconstituted core samples from the Pearl River Mouth Basin to address this gap. Our results reveal extreme vertical permeability heterogeneity (spanning 10−6 to 10−1 mD) within Yuehai and Hanjiang Formation caprocks. Critically, permeability and scCO2 breakthrough pressure are decoupled: breakthrough pressure is controlled by maximum pore-throat radius, while breakthrough time depends on post-breakthrough pore network topology. ScCO2-brine-rock interactions induce pronounced geomechanical weakening, with uniaxial compressive strength decreasing by up to 71.7% and the elastic modulus reducing, while a substantial increase in Poisson’s ratio signifies a fundamental transition from brittle to ductile behavior. We have developed a comprehensive framework to delineate potential CO2 migration pathways. Hanjiang Formation Section 1 (represented by sample A3) exhibits exceptional sealing properties, characterized by ultra-low permeability (2.41 × 10−6 mD), high breakthrough pressure (>16 MPa), and extended breakthrough time (>30 min). These attributes suggest that CO2 injection into the target saline aquifer at depths between 1470 and 1500 m, situated beneath this interval, can be deemed secure with a high potential for effective long-term containment. These findings provide essential insights for optimizing offshore CO2 sequestration site selection and injection pressure management to ensure long-term containment security.

Effects of natural fractures in cap rock on CO2 geological storage: Sanduo Formation and Dainan Formation of the early Eocene epoch in the Gaoyou Sag of the Subei Basin

This study assesses the CO₂ storage potential of an aging well in the South Sumatra Basin through the interpretation of conventional well log data, including gamma ray (GR), bulk density (RHOB), neutron porosity (NPHI), deep and shallow resistivity logs (LLD and MSFL), and caliper measurements. The evaluated interval, ranging from 1200 to 1800 meters, is subdivided into an upper formation (1200-1500 m) and a lower formation (1500-1800 m). The upper formation exhibits low gamma ray values but minimal separation between porosity and resistivity logs, suggesting low porosity and permeability, characteristics indicative of a potential cap rock. In contrast, the lower formation reveals distinct separation in both porosity and resistivity responses below 1650 meters, indicative of a porous sandstone with favorable reservoir properties. Petrophysical analysis yields an average effective porosity of 14.4% and an irreducible water saturation of 6.4%. Volumetric calculations estimate a theoretical CO₂ storage capacity of approximately 1.21 million metric tons per square kilometer. These findings demonstrate the feasibility of repurposing aging wells for CO₂ sequestration and emphasize the utility of well log analysis in early-stage site screening, particularly in data limited sedimentary basins.

The travertine formation subject to the study is located in the near northeast of Elmalı Village (Bingöl) located at approximately 28th km of Bingöl-Karlıova highway on the Ilıca segment, which is one of the important segments of the left-lateral strike-slip East Anatolian Fault Zone, which is the second largest neotectonic structure in Turkey. The outcrops of Paleozoic-Mesozoic Bitlis Metamorphites, which play a source rock role in travertine formation, are mostly characterized by marbles around Bingöl. It is thought that Solhan Volcanics, which are mainly composed of pyroclastic rocks, play a cap rock role that maintains this temperature. Ca and Mg concentrations in the samples are the highest elements with 396226 ppm and 2713.84 ppm, respectively. From stable isotope analyses, δ13C values range from +7.7 to +11.2 (‰ PDB); δ18O values are between -9.8 and -11.7 (‰PDB). U-Th age data obtained from the samples indicate that travertine deposition started at least 69672 years ago.

Geological sequestration of carbon dioxide (CO2), being one of the important methods to deal with anthropogenic climate change, is to reduce the large scale emission to the atmosphere. Among all the trapping mechanisms, mineral carbonation, i.e., the reaction between CO₂ and silicate minerals to form stable, solid carbonate minerals, is considered the most secure and long-term solution to effectively isolate CO₂. This paper carries out a thorough and extended examination of the long-term stability of CO2 sequestered through in-situ mineral carbonation. It probes the key geochemical reactions shaping the change of injected supercritical CO₂ into solid mineral forms, focusing mainly on mafic and ultramafic rock formations abundant with olivine, pyroxene and plagioclase. The assessment framework described here looks at main interdependent factors that affect secure storage for an extended amount of time. Includes a detailed analysis of intrinsic reaction kinetics of silicate dissolution, evolution of host rock’s geomechanical property under coupled thermo-hydro-mechanical-chemical (THMC) stress, and the whole-scale integrity of the overlying caprock. Investigate how varying porosity and permeability brought on by competing mineral dissolution and carbonate precipitation alter the reservoir’s hydraulic properties and long term containment system. In addition to that the paper talks about the role of advanced numerical modeling of the reactive transport to predict the behavior of the storage reservoir over a span of few decades to millennial scales. And they’re important for predicting the rate of mineralization, the extent of the carbonate precipitates, and any geomechanical risks like earthquakes or cap rock fracturing. Lastly we look at state-of -the -art observation and inspection technologies that are needed for observing the subsurface plume and verifying the advancing mineral carbonation and certifying the long -term stable and environmentally safe sequestration project. The integrated assessment shows that although mineral carbonation provides the most solid solution for carbon dioxide storage, it is still based on the strict, site-specific examination of geological, geochemical, and geomechanical parameters from the laboratory scale to the field scale.