Structural Trap Research Articles

Analysis of Hydrocarbon Enrichment in Tight Sandstone Reservoirs in the Eastern Baiyun Depression

Based on the special geological background of the east and north slopes of the Baiyun Depression, the development conditions of Paleogene structure–lithology traps, the development conditions of high-quality reservoirs and the difficulty in characterizing the distribution characteristics are studied in this paper. It is concluded that the eastern Baiyun is located on the Baiyun–Liwan continental–oceanic large-scale intershell separation system, with a complex tectonic background and a tectono-sedimentary pattern of “fault and uplift interlocking and uplift and depression interphase”. The palaeo source sink system of the low bulge in the east of Yundong is restored, the favorable position of reservoir collective development and the favorable characteristics of reservoir–cap assemblage are clarified, and the paleo-geomorphology and sedimentary filling evolution law are clarified. Guided by the drive of oil and gas accumulation, three types of large and medium-sized structure–stratigraphic traps have been implemented in the eastern Baiyun system, including the convex inclined end, the restricted fault gully and the magmatic floor intrusion, and the corresponding oil and gas accumulation models have been perfected. By studying the structure, source and sink system and trap characterization of the eastern Baiyun basin, the development conditions and exploration direction of the large and medium-sized Palaeogene traps are systematically summarized.

Sandstone wettability in supercritical CO2-brine-rock interactions evaluated with 13C and 1H magnetic resonance

During the first decades of geologic CO2 storage in saline formations and depleted reservoirs, structural trapping is the most important storage mechanism. The effectiveness of CO2 containment hinges on the assumption that the sealing formation remains water wet in the presence of dense CO2. In this work, multiple 13C and 1H magnetic resonance (MR) methodologies were employed for the first time to evaluate the interactions between supercritical CO2, brine, and the pore surface of a Berea sandstone core plug under reservoir conditions. These studies employed a novel variable field superconducting MR and magnetic resonance imaging (MRI) instrument which permitted sequential 1H and 13C measurements of core plugs at high-pressure and high-temperature. To systematically study the wettability of rock core exposed to supercritical CO2, four experiments were designed including bulk CO2 in a high-pressure vessel, bulk CO2-brine, 13CO2 in dried rock core, and a 13CO2-brine-rock experiment.The measured 13C and 1H MR relaxation times in this work indicate that the Berea sandstone remained strongly water-wet when the brine saturated core plug was exposed to supercritical CO2 under reservoir conditions. For both 13C and 1H, T1 relaxation times provide more reliable wettability evaluation as compared to T2 due to the impact of molecular diffusion through internal magnetic field gradients. One-dimensional (1D) MRI was employed to spatially resolve 13CO2 and brine in the core plug. Two-dimensional (2D) MRI was able to image 13CO2 and brine in a PEEK vessel. The quantities of CO2 and brine in the core plug were determined from the MR signal intensities of 13CO2 and brine.

The monazite record of (ultra)high-temperature metamorphism in southern Madagascar: Gondwana terrane correlations and structural trapping of hot middle crust

Ancient orogens eroded to midcrustal levels provide insight about strain accommodation, metamorphism, and melting in Himalaya-type continent-continent collisions. This study focuses on the Neoproterozoic–Cambrian Eastern-Africa / Kuunga orogen exposed in Madagascar, where uncertainty about the terrane correlations, and therefore structural framework, of the orogen persists. We present a comprehensive dataset of monazite petrochronology and thermobarometry across the southern Madagascar basement to quantify the regional and temporal variability of metamorphism. We argue that the ultrahigh-temperature Anosyen domain and associated Androyen domain have a shared geological history, recording two successive tectonic events at 630–600 Ma and 580–500 Ma. Other Madagascar domains record primarily the former (Vohibory domain to the west) or latter (all other domains to the northeast) event. From this inference, we discuss terrane correlations with Africa and India, then present a structural framework for the orogen in which the Anosyen–Androyen domain was structurally confined in a central, lithosphere-scale transpressional shear system between divergent, diachronous thrust belts. By limiting exhumation, extrusion, and collapse, the structural trapping of the Androyen–Anosyen domain facilitated longer-lasting, higher- T metamorphism than associated rocks in the adjacent nappe systems. Such structural trapping may be an important control on high- T metamorphism in the cores of Himalaya-type orogens in general.

Subsurface storage capacity in structural traps in underexplored sedimentary basins: hydrogen (H 2 ) and carbon dioxide (CO 2 ) storage on the Irish Atlantic margin

Methodologies for storage assessment developed for basins with dense data coverage are typically not optimally applicable to underexplored sedimentary basins. To address this, a methodology and workflow for storage assessment in underexplored basins is presented which uses existing datasets to identify structural traps and populate a Fluid-in-Place equation which can be used for a variety of gases including CO 2 and H 2 . This is then applied to the Irish Atlantic margin; Jurassic, Triassic and Carboniferous reservoirs are investigated to understand their reservoir quality and extent, and related seals. Structural trap types are described and the theoretical capacities of three candidate sites with varying data coverage are calculated. The results highlight the potential for underexplored sedimentary basins on the Irish Atlantic margin to support offshore renewable energy projects and reduce Ireland's CO 2 emissions. This workflow is applicable to a variety of underexplored sedimentary basins and emphasizes the utility of legacy hydrocarbon datasets for early-stage subsurface storage assessment. Other aspects of energy storage are also discussed, including anthropogenic salt caverns, other candidate reservoir–seal pairs, and the potential for collaborative infrastructure development with CO 2 emitters and renewable energy projects.

An integrated dynamic modeling workflow for acid gas and CO2 geologic storage screening in saline aquifers with faults: A case study in Western Canada

This study investigates the feasibility of storing the acid gas produced from the oil and gas facilities in Southern Saskatchewan into the Basal Sand aquifer using a coupled wellbore-aquifer-compositional reservoir model. The simulations investigate the pressure change around the fault in proximity of the primary storage location incorporating the influence of reservoir permeability, fault transmissibility, and wellbore configuration, on the factors critical to safe and efficient storage, such as plume migration, pressure changes, and CO2 storage capacity. A compositional fluid model created using an equation of state was integrated into the reservoir model. Simultaneous incorporation of fault transmissibility, phase solubility, water salinity, temporal in-situ hysteresis and structural trapping, and in-situ compositional tracking of individual gas components is considered as the main novelty of this work. The main challenge of the study was the lack of available data to characterize the aquifer. To this end, a comprehensive workflow of reservoir studies and modeling was applied to reduce the uncertainties and evaluate the site selection. The Basal sand scoping models reveal that the aquifer is expected to handle the required disposal volume given its extent. The injected acid gas plume migrates laterally and preferentially towards the northwest, away from the fault, owing to the aquifer's geological structure. CO2 remains entirely in the supercritical state, offering storage advantages due to its lower volume. The reservoir permeability significantly impacts the pressure patterns with lower permeability formations triggering higher wellhead injection pressures. Substantial pressure increases around the sealing fault can be observed. Pressure changes of 110 kPa (16 psi) to over 400 kPa (58 psi) were observed at the fault segment after 20 years of continuous gas injection for the expected range of reservoir properties. Mitigation strategies to minimize the increase in fault pressure entail relocating the injection site away from the fault or utilizing a horizontal well trajectory and using an observation well near the fault for monitoring any pressure buildup and slippage.

Effects of Aqueous Solubility and Geochemistry on CO2 Storage in Offshore Basins

The increasing global focus on carbon capture and storage (CCS) has highlighted the potential for offshore CO2 sequestration, particularly following recent successes in onshore projects. This research investigates the qualitative analysis of carbon trapping efficiency in offshore basins, employing a GEM simulator to incorporate factors such as aqueous solubility and geochemistry. The findings reveal that anticlines represent ideal geological structures for carbon storage, effectively trapping a significant portion of injected CO2. For effective mineralization, it is crucial to dissolve CO2 into saline aquifers to generate H+, which facilitates the release of Ca2+ and Al3+ from anorthite. This process leads to the dissolution of anorthite and the precipitation of kaolinite, while calcite transitions from a dissolved state to a precipitated state over time. The analysis indicates that structural trapping provides the highest storage contribution during the injection phase, whereas residual gas trapping becomes dominant by the end of the simulation. Notably, it is observed that the storage contribution of structural trapping decreases from 28.39% to 19.05%, and the percentage increase in storage contributions of residual gas, solubility, ionic, and mineral trapping are 4.12%, 3.25%, 1.69%, and 0.28% for CO2 plus water injection, thereby improving the long-term security of CO2 storage in offshore basins. It is most beneficial to optimize the layout and design of the injection well to ensure a uniform distribution of carbon dioxide and to increase the injection rate.

CO2 trapping dynamics in tight sandstone: Insights into trapping mechanisms in Mae Moh's reservoir

The reliance on fossil fuels is a major contributor to increased anthropogenic CO2 emissions, driving global challenges such as climate change through the greenhouse effect. Carbon capture and storage (CCS) is a promising interdisciplinary technology aimed at mitigating these emissions by securely sequestering gigatons of CO2. This study focuses on the feasibility of storing point-source CO2 emissions in saline formations, with a particular emphasis on the Mae Moh coal-fired power plant in Lampang, Thailand, which is located near its associated coal mine. The region presents challenges due to tight sandstone reservoirs buried over 2000 m deep. With reservoir simulation, this study evaluates the impact of various factors on CO2 containment and trapping in these geological settings. Results show that elevated temperatures decrease structural trapping of 43.0%–28.9% and increase solubility trapping of 28.55%–46.5%, at 40 °C and 80 °C respectively. Hysteresis is found to enhance residual trapping by immobilizing up to 31.1% of CO2 within pore spaces at 0.5. Permeability heterogeneity has a minimal impact on overall trapping efficiency due to the less heterogeneity of the tight sandstone. However, the kV/kH ratio significantly influences vertical CO2 migration which resulted in residual trapping at its highest at the ratio of 0.1, while lower ratios support lateral dispersion. Moderate rock compressibility values are identified as optimal for structural and residual trapping, while extreme compressibility enhances solubility trapping by up to 30%. These findings emphasize the complexity of CO2 trapping mechanisms in tight sandstone formations, emphasizing the need for careful consideration of key factors in CCS projects.

Integrated Sequence Stratigraphic and Seismic Facies Analysis for Hydrocarbon Prospectivity of the Taranaki Basin, New Zealand

This study analyses the hydrocarbon potential and basin characteristics of the Taranaki Basin in New Zealand, the country's primary petroleum-producing region. The research, which uses a robust methodology involving 2D seismic data, well logs, and other geological information, examines the basin's stratigraphy, structural features, and petroleum systems. Key findings include the identification of two genetic sequences with associated system tracts, multiple reservoir and source rock units, and both structural and stratigraphic trapping mechanisms. Seismic facies analysis revealed eight distinct facies types which characterize the depositional environments. Play fairway mapping identified sweet spots where all petroleum system elements overlap. Risk assessment highlighted factors like gas chimneys and fault-compromised seals. The study concludes by presenting the geologic chance of success for three identified plays and one prospect in different stratigraphic intervals. This comprehensive analysis provides new insights into the under-explored portions of the Taranaki Basin and its hydrocarbon potential. By enhancing the understanding of the basin's stratigraphic architecture and depositional history, this study aims to improve reservoir distribution and quality predictability. Moreover, integrating seismic facies analysis with sequence stratigraphy offers a robust tool for delineating potential hydrocarbon-bearing zones, thereby reducing exploration risk and aiding the efficient reassessment of existing prospective zones and future exploration efforts.

Modelowe i empiryczne podejście do oceny parametrów petrofizycznych skał na przykładzie złoża gazu Dhodak w Pakistanie

The main aim of the presented study was to perform an analysis of petrophysical rock parameters for the Pab Formation, which is a potential reservoir, located at four-depth intervals within the Dhodak Gas Field. The Pab Formation in the studied wells is mostly composed of the well-sorted sandstone. The intervals for the study were selected by applying a gamma ray log cut-off of 40%. A Matlab code that is user-friendly and contains empirical and numerical models (Raymor’s, Han's, Castagna’s, Jizba, Blangy, and Gardner's models) was designed with the purpose of providing an interpretation of rock physics parameters in reservoirs. The results indicate that the Pab Formation is mainly saturated with hydrocarbons and possesses sufficient porosity (i.e. between 8 and 38%). According to the cross-plot models, there are a few zones within the Pab Formation that are weakly consolidated. These zones are located at depths of 2377–2404 m and 2418–2430 m. However, the same area is classified as tight gas sandstone and is located between 2330 to 2343 m. The results of the study indicate that the Pab Formation is potentially saturated with hydrocarbons. These findings were based on structural and rock physics assessments of the study area. The approach presented in this work is also helpful for structural trap evaluation. In addition, the petrophysical rock parameter models developed can contribute to reducing the risks associated with hydrocarbon exploration, enabling accurate representation of subsurface conditions and improving reservoir forecasting capabilities in oil producing areas.

Estimation of CO2-Brine Interfacial Tension Based on an Advanced Intelligent Algorithm Model: Application for Carbon Saline Aquifer Sequestration.

The emission reduction of the main greenhouse gas, CO2, can be achieved via carbon capture, utilization, and storage (CCUS) technology. Geological carbon storage (GCS) projects, especially CO2 storage in deep saline aquifers, are the most promising methods for meeting the net zero emission goal. The safety and efficiency of CO2 saline aquifer storage are primarily controlled by structural and capillary trapping, which are significantly influenced by the interactions between fluid and solid phases in terms of the interfacial tension (IFT) between the injected CO2 and brine at the reservoir site. In this study, a model based on the random forest (RF) model and the Bayesian optimization (BO) algorithm was developed to estimate the IFT between the pure and impure gas-brine binary systems for application to CO2 saline aquifer sequestration. Then three heuristic algorithms were applied to validate the accuracy and efficiency of the established model. The results of this study indicate that among the four mixed models, the Bayesian optimized random forest model fits the experimental data with the smallest root-mean-square error (RMSE = 1.7705) and mean absolute percentage error (MAPE = 2.0687%) and a high coefficient of determination (R2 = 0.9729). Then the IFT values predicted via this model were used as an input parameter to estimate the CO2 sequestration capacity of saline aquifers at different depths in the Tarim Basin of Xinjiang, China. The burial depth had a limited influence on the CO2 storage capacity.

Gigaton commercial-scale carbon storage and mineralization potential in stacked Columbia River basalt reservoirs

This work presents a detailed supercritical CO2 storage resource estimation for the stacked basalt reservoirs in the Grande Ronde Basalt of the Columbia River Basalt Group in eastern Washington and Oregon. The assessment aims to derisk the commercialization potential of geologic carbon storage in basalt by leveraging both structural and mineralization trapping of CO2 in basalt. The structural closures formed by anticlinal ridges and synclinal valleys in Yakima Fold Belt are excellent physical traps to accommodate injected supercritical CO2. Rigorous hydraulic testing, well logs and simulation results from the Wallula Basalt Pilot #1 well showed the occurrence of 17 suitable permeable injection zones (up to 2,496 mD) intercalated with dense seals (∼2.6E-10 mD) in the Grand Ronde Basalt. In addition, geochemical studies showed fast reactions between supercritical CO2 and dissolved basalt minerals to form stable carbonates. Our calculation indicates up to 40 gigatons (P90) of mineralization storage resources exist in the Grande Ronde Basalt reservoirs.

Investigation of non-chemical CO2 microbubbles for enhanced oil recovery and carbon sequestration in heterogeneous porous media

Non-chemical CO2 microbubble (MB) is a promising environmentally friendly technology for enhanced oil recovery (EOR) and carbon sequestration. Understanding the interaction between non-chemical CO2 MB and oil phases in porous media is crucial for optimizing the design of CO2 MB to enhance both EOR and carbon sequestration efforts. This study explores the impact of oil on the conformance control of non-chemical MB and conducts a case study on their potential for EOR and carbon sequestration in a heterogeneous reservoir. First, experimental results reveal that MB's conformance control is impacted by the presence of oil, with varying degrees of impairment depending on oil composition. Then, reservoir simulations demonstrate that MB outperforms conventional CO2 flooding and water-alternating-gas (WAG), achieving a final recovery of 77.48% of original oil in place compared to 66.79% of original oil in place for CO2 flooding and 68.19% of original oil in place for WAG. Sensitivity analyses highlight the importance of parameters such as gas-liquid ratio of MB, reservoir heterogeneity, and reservoir thickness in MB's EOR performance. Finally, CO2 storage efficiency analyses show that MB exhibits superior CO2 storage efficiency, with higher structural and solubility trapping compared to WAG. The study concludes that MB technology holds promise for EOR and carbon sequestration, contributing to efforts toward carbon neutrality and sustainable oil recovery practices. These findings provide valuable insights for optimizing MB applications in field-scale operations and advancing toward a more environmentally sustainable energy industry.

The research on fault and structural trap of the Weixinan Sag, Beibuwan Basin, South China Sea

The Weixinan Sag in Beibuwan Basin is a pilot area of the offshore exploration and development integrated technology. The main oil bearing layers, first member of Liushagang formation and third member of Weizhou formation, develop many fault systems and structural traps. The key factors of the offshore exploration and development integrated technology are”the fault research”and “the effectiveness of structural trap”. Fault research includes the study of the geometry, dynamics, kinematics characteristics of fault, and the division of fault system. The effectiveness of structural trap include analogical studies on the structural characteristics of traps, quantitative studies on fault lateral sealability, fault vertical sealability, and prediction technology of oil column height. Synthesizing the relationship of the law of oil and gas distribution,the differential fault system in the internal of the No. 2 fault zone, and the effectiveness research of traps, the fault-controlled reservoir laws and the dominant fault-controlled reservoir mode are obtained. The research on fault and trap of offshore integrated exploration and development has been successfully applied in the Weixinan Sag. The 37 of 45 development evaluation wells have been drilled successfully and the drilling success rate is 82%. It has promoted the ODP(original drilling project) implementation of 5 oilfields, the adjustment implementation of 8 oilfields and made important contribution to the increase of reserves and production in the Weixinan Sag.

Sealing faults and fluid-induced seismicity.

Sealing faults are nearly impermeable barriers that can form boundaries between subsurface pore-pressure domains. In hydrocarbon systems, sealing faults commonly form part of a structural trap; they are thus important elements for future storage of CO2 and other gases in depleted reservoirs. The Triassic Montney Formation in western Canada hosts low-permeability gas reservoirs containing sealing faults that have previously been assumed to compartmentalize pressure domains. In this study, we show that the distribution of induced seismicity associated with hydraulic fracturing (HF) exhibits a statistically significant spatial correlation with zones of high lateral gradient in pore pressure. These high-gradient zones are interpreted as sealing fault systems. The largest induced seismicity sequence, including a 4.5 ML mainshock on 30 November 2018, occurred during HF treatments in two horizontal wells, between which there is an exceptionally large contrast (~10 MPa) in measured pore pressure. Numerical simulation of a simplified model of a hydraulic fracture intersecting a nearby vertical fault, followed by fault rupture using rate-and-state friction rheology, generates results that are in good agreement with observed strike-slip faulting near one of the HF wells. Our study demonstrates that sealing faults exhibit previously unrecognized behaviour that may be important for understanding induced seismicity risk. This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'.

Effect of Infinite Volume on Structural Trapping Performance during Carbon dioxide Sequestration Processes

Effect of Infinite Volume on Structural Trapping Performance during Carbon dioxide Sequestration Processes

Investigation of gas residuals in sandstone formations via X-ray core-flooding experiments: Implication for subsurface hydrogen storage

The production and utilization of hydrogen (H2) as a clean energy source offer a promising solution towards achieving net-zero carbon emissions. Utilizing sandstone formations for geological hydrogen storage presents a viable option for the practical implementation of the hydrogen economy, offering both safe and large-scale containment capabilities. Accurate assessment of gas displacement behavior in porous media plays a critical role in understanding gas saturation, gas residual, and long-term storage duration. However, there are limited studies available on dynamic displacements for hydrogen storage applications. This study aims to enhance the understanding of gas flow behavior in sandstone rocks for different gas types and determine the role of capillary pressure and gas wettability during hydrogen storage. A series of gas core-flooding experiments are performed on a brine-saturated sandstone core sample using three different gases (CO2, CH4, and H2). X-ray scanning technique is applied to detect the gas saturation and gas residual after the core-flooding experiments. The results indicate that the average gas saturation ranges between 25 and 40%, with zero gas residual for all gases, suggesting that the gas residuals in this clean sandstone sample are unaffected by the gas type. Initially, the capillary pressure profile for the sample displayed low brine saturation at 200 psi, indicating very low capillary pressure in the sample due to the high permeability and large pore radius, despite the strong water-wetting behavior of the sample. Moreover, the obtained results indicate the high potential for gas recovery (especially for hydrogen during withdrawal cycles), and the high displacement efficiency in sandstone rocks. The reported low gas residual suggests that the wettability of the rock is not affected by gas injection, and it appears that the wettability and capillary pressure are not the controlling factors for gas storage in this sandstone sample. This observation suggests that the structural trapping mechanism is most likely to be the dominant trapping mechanism in this shallow high permeable sandstone rock. Also, the injection of cushion gases such as CO2 and CH4 indicated similar results to hydrogen injection, due to the low capillary pressure and high permeability in this sandstone sample. The findings of this study can greatly enhance the understanding of gas injection, displacement behavior, and gas residuals in sandstone rocks related to underground hydrogen storage.

Probabilistic Determination of the Role of Faults and Intrusions in Helium‐Rich Gas Fields Formation

AbstractNatural gas fields with economic helium (>0.3 He %) require the radioactive decay of crustal uranium (U) and thorium (Th) to generate He and tectonic/structural regimes favorable to releasing and concentrating He. An unknown is determining the role of faults and structural features in focusing deep‐seated He sources on shallow accumulations. We tested the correlation between high‐He wells (n = 94) and structural features using a new high‐resolution aeromagnetic survey in the Four Corners area, USA. A depth‐to‐basement map with basement lineaments/faults, an intrusion map, and a flattened basement structural high map were created using Werner deconvolution algorithms by combining magnetic, gravity, and topography data with magnetic and gravity depth profiles. We show quantitatively (via analysis of variance) that a non‐random process controls the relationship between He (>0.3%) and both basement faults and intrusions: 88% of high‐He wells occur <1 km of basement faults; and 85% of high‐He wells occur <1 km of intrusions. As He % increases, the distance to the structural features decreases. Strong spatial/statistical correlations of He wells to both basement faults and intrusions suggest that advective transport via faults/intrusions facilitates He migration. The role of gas phase buoyancy and structural trapping is confirmed: 88% of high‐He occurs within basement structural highs, and 91% of the remaining wells are <1 km from intrusions (potential structural high). We present a composite figure to illustrate how a probabilistic approach can be used as a predictive model to improve He exploration success by targeting zones of intersection of basement faults and intrusions within basement structural highs.

Impact of formation conditions and well configurations on underground hydrogen storage

Converting surplus renewable energy into hydrogen is considered an efficient technique to balance renewable energy generation and demand, which necessitates large-scale underground hydrogen storage (UHS) in geological formations. While the H2 trapping mechanisms and fluid flow behavior have been rigorously reported in past studies, the performance of UHS is strongly influenced by the formation conditions and well configurations, which have not been explored thoroughly. To this end, this study investigated the sensitivity of UHS efficiency to variations in formation temperature, brine salinity, well placement, and well perforations. For each scenario, key aspects such as plume migration dynamics, residual trapping, dissolution trapping, structural trapping, H2 recovery factor, and water production were thoroughly analyzed. The results indicate that factors such as formation temperature, brine salinity, and well perforations have a negligible impact on the shape of the overall H2 plume. However, these significantly influence local H2 saturations. Formations with higher temperatures, central dome well placement, and production wells in the top layers exhibit a higher H2 recovery factor (as high as 69.93 %), whereas salinity plays a minor role in H2 trapping and withdrawal (maximum change observed is ∼1.7 % and ∼1.4 % for trapping and withdrawal respectively with a 20 wt % increase in salinity). In addition, brine production is strongly influenced by the formation conditions and well configurations (e.g., ∼3965 m3 brine produced under at 343 K and ∼26,000 m3 for non-central well placement), due to variations in H2/brine properties, such as density and viscosity, and the extent of H2 accumulation.

Static contact angle, interfacial tension, and column height measurements for underground hydrogen storage

Geological porous media are key for large-scale hydrogen (H2) storage and production, where fluid interactions at interfaces and within rock formations are vital for effective gas containment. Although advancements have been achieved in comprehending structural trapping for estimating column height (CH), additional insights are required regarding how pore size impacts this estimation. Currently, CH estimates often consider seal rock potential, without including the capillary contribution from reservoir rock pore for structural trapping capacity assessment. This study measures the static contact angle (CA) on Wolfcamp (WC) Shale and interfacial tension (IFT) under modified drainage and imbibition conditions at temperatures of 30 and 50°C, pressures ranging from 500 to 3000 psia, and a salinity of 10 wt% sodium chloride. Subsequently, the static gas CH was calculated, accounting for contributions from the caprock pores alone and both the caprock and reservoir, to assess the structural sealing capacity of the caprock layer. The experimental procedures are comprehensively detailed in this paper. The outcome indicates that the static CA after drainage for H2)/brine/WC shale rises with pressure as the static CA after imbibition decreases. Both CAs decrease with increasing temperatures. For H2/brine systems, both drainage and imbibition IFTs decline with increasing pressure and temperature. Calculated CHs reveal that lower CAs substantially impact the gas trapping capacity beneath the caprock. In summary, this study highlights the preference for the drainage method in measuring IFT and CA to evaluate the potential structural trapping capacity of injected gas by the overlying caprock.

Influence of extensional strike-slip fault systems on hydrocarbon accumulation: case studies from Huanghekoudong and Miaoxi’nan sub-sags

Extensional strike-slip basins have unique structural features that influence both sub-sags and traps. Despite previous investigations into the extension-strike-slip fault system, there remains a gap in the comprehensive analysis of its influence on sub-sag formation and trap development. The Huanghekoudong and Miaoxi’nan sub-sags within the Bohai Bay Basin, intersected by the Tan-Lu Fault Zone, offer exemplary cases for examining the interplay between strike-slip and extensional tectonic regimes. The neotectonic strike-slip movements along the Tan-Lu Fault Zone have given rise to various extensional strike-slip overlap zones in these sub-sags, rendering these locales ideal for investigating the dynamics of strike-slip and extensional tectonic processes. Employing three-dimensional seismic data, well logs, and a newly constructed sequence stratigraphic framework, our research delineates the geometric and kinematic phenomena characteristic of the extensional strike-slip fault system, including the dynamics of extensional fault deformation and interaction through time. By scrutinizing the fault system’s vital role in shaping sub-sag evolution and trap genesis, we present a comprehensive model that significantly contributes to our understanding of structural trapping dynamics. This model not only fine-tunes existing trapping models but also offers invaluable insights for future exploration strategies within the Bohai Bay Basin and other similar extensional strike-slip basins worldwide. Our findings highlight the novel and significant implications of the extensional strike-slip fault system in controlling sub-sag and trap features, thus bridging a notable gap in existing geotechnical knowledge.