Search

Helium reservoirs, as an indispensable and scarce strategic resource, can be categorized into two primary origins: crust- and mantle-sourced. Understanding the mechanisms of its formation and accumulation is a crucial challenge in helium exploration. Previous work on helium exploration has mainly focused on crustal helium, while mantle-sourced helium-rich reservoirs have been overlooked. Helium reservoirs with both a crustal and a mantle source exhibit higher helium abundance than that of crustal helium reservoirs and are sporadically distributed in Neogene basins worldwide, but their formation and evolution is poorly understood. In Eastern China, several Neogene basins preserve high quality crust/mantle helium-rich reservoirs, and in this study, we use the Subei Basin as a case study to investigate processes controlling He accumulation and storage. The helium reservoirs can be classified into two types based on the lithological nature of the structural traps: sand reservoir with mud cap and basalt reservoirs with mud cap. The main controlling factors for the formation of crust–mantle helium-rich reservoirs include deep-seated faults, magmatic activity, and mineralization of mantle-derived CO2. Deep-seated faults, along with their associated strike-slip faults, serve as favourable pathways for mantle-derived helium migration and magma upwelling. Magmatic activities serve as the material source for mantle-derived helium as well as the carrier medium in the migration of mantle-derived volatiles. The presence of well-developed sandstone and basalt reservoirs, along with mudstone cap rocks, and the dissolution and mineralization caused by mantle-derived CO2 are important factors in helium accumulation and preservation. [ABSTRACT FROM AUTHOR]

ABSTRACT As the exploration of deep‐seated oil and gas resources in the Turpan‐Hami Basin intensifies, there is an urgent need to thoroughly depict the geological characteristics of newly uncovered, underexplored strata in sub‐sag centers. This study undertakes the inaugural systematic geochemical analysis of mudstones atop the Sangonghe Formation, including palynological identification, maceral identification, biomarker analysis, total organic carbon (TOC) analysis, and pyrolysis. The findings reveal that the mudstone sequence, as the target layer, was deposited in a warm and moist paleoclimate and a weakly reducing to weakly oxidising saline water environment, fostering the growth of prolific algae and bacteria, thus ensuring substantial foundational materials for source rock formation. The organic matter in the mudstone sequence displays pronounced laminar accumulation. Despite the overall modest abundance, the organic matter features notable hydrocarbon‐generating potential per unit of organic carbon and favourable types. Humic‐sapropelic kerogens (type II1) are found in the mudstones, with organic matter generally reaching a mature to highly mature stage. These characteristics establish the mudstones as effective source rocks, furthermore, the hydrocarbon expulsion in the Xishanyao Formation precedes that of the Sangonghe Formation and that both formations constitute a sequential process in terms of hydrocarbon generation and expulsion timing and hydrocarbon contribution. Reanalyzing this mudstone sequence not only revises prior geological understanding of it as direct cap rocks, but also facilitates the reclassification of deep‐seated strata into three distinct petroleum systems. Centered around this source rock layer, dual modes, namely the “lower‐source rock and upper‐reservoir” and the “ lower‐reservoir and upper‐source rock” modes can be formed. These new insights will offer profound implications for hydrocarbon resource evaluation and future hydrocarbon exploration endeavours in the Shuixigou Group within the Taibei sag. [ABSTRACT FROM AUTHOR]

The North Sea Basin is the most important oil and gas producing area in Europe and the birthplace of many classic petroleum geological theories. From the perspective of multi-spheric interactions in the Earth, this study investigated the rift-foreland-rift evolution process of the North Sea Basin, which was controlled by the deep dynamic driving forces of the continental collision orogeny, mantle plume uplift, and intraplate deformation. The North Sea Basin was found to have drifted northward since the Carboniferous and passed through the low-latitude Hadley and the mid-latitude Ferrel cells. Two sets of main hydrocarbon source rocks have formed, the coals and coal measures of the Upper Carboniferous Westphalian and the marine shale of the Upper Jurassic Kimmeridge Clay Formation. We propose that the deep processes, tectonic activity, and transgression-climate evolution jointly controlled the types and horizons of the source rocks, reservoirs, and seals in different regions of the North Sea Basin. In the southern North Sea Basin, a Carboniferous-Lower Triassic gas-rich petroleum system was formed, which is characterized by transitional coal measure source rocks, desert aeolian sandstone reservoirs, and evaporite cap rocks. In the northern North Sea Basin, an Upper Triassic-Paleogene oil-rich petroleum system was formed, which is characterized by marine graben-type source rocks, deltaic sandstone and marine limestone reservoirs, and marine tight marl and shale cap rocks. The late tectonic burial and uplift in the North Sea Basin further controlled the processes of oil and gas generation and accumulation, ultimately leading to a differential distribution pattern which is oil rich in the northern part and gas rich in the southern part of the basin. In the future, there is an urgent need to re-examine the mechanisms for the petroleum generation and accumulation in large mature exploration areas (e.g., super basins such as the North Sea) and low exploration areas (e.g., the Okhotsk Sea and Arctic regions) from the perspective of multi-spheric interactions in the Earth in order to provide new theoretical support for increasing the identification of oil and gas reserves globally. The development of artificial intelligence in the petroleum industry should focus on the massive amount of exploration and geological data collected in the North Sea Basin. Through digital geological innovation, carbon neutral comprehensive utilization of oil, gas, and associated resources (e.g., helium and hydrogen) can be achieved, providing a new paradigm for global oil and gas exploration and development. [ABSTRACT FROM AUTHOR]

The static sealing of underground gas storage (UGS), including the integrity of cap rocks and the stability of faults, is analyzed from a macro perspective using a comprehensive geological evaluation method. Changes in pore structure, permeability, and mechanical strength of cap rocks under cyclic loads may impact the rock sealing integrity during the injection and recovery phases of UGS. In this work, the mechanical deformation and failure tests of rocks, as well as rock damage tests under alternating loads, are conducted to analyze the changes in the strength and permeability of rocks under multiple-cycle intense injection and recovery of UGS. Additionally, this study proposes an evaluation method for the dynamic sealing performance of UGS cap rocks under multi-cycle alternating loads. The findings suggest that the failure strength (70%) can be used as the critical value for rock failure, thus providing theoretical support for determining the upper limit of operating pressure and the number of injection-recovery cycles for the safe operation of a UGS system. [ABSTRACT FROM AUTHOR]

The increasing level of anthropogenic CO2 in the atmosphere has made it imperative to investigate an efficient method for carbon sequestration. Geological carbon sequestration presents a viable path to mitigate greenhouse gas emissions by sequestering the captured CO2 deep underground in rock formations to store it permanently. Geochemistry, as the cornerstone of geological CO2 sequestration (GCS), plays an indispensable role. Therefore, it is not just timely but also urgent to undertake a comprehensive review of studies conducted in this area, articulate gaps and findings, and give directions for future research areas. This paper reviews geochemistry in terms of the sequestration of CO2 in geological formations, addressing mechanisms of trapping, challenges, and ways of mitigating challenges in trapping mechanisms; mineralization and methods of accelerating mineralization; and the interaction between rock, brine, and CO2 for the long-term containment and storage of CO2. Mixing CO2 with brine before or during injection, using microbes, selecting sedimentary reservoirs with reactive minerals, co-injection of carbonate anhydrase, and enhancing the surface area of reactive minerals are some of the mechanisms used to enhance mineral trapping in GCS applications. This review also addresses the potential challenges and opportunities associated with geological CO2 storage. Challenges include caprock integrity, understanding the lasting effects of storing CO2 on geological formations, developing reliable models for monitoring CO2–brine–rock interactions, CO2 impurities, and addressing public concerns about safety and environmental impacts. Conversely, opportunities in the sequestration of CO2 lie in the vast potential for storing CO2 in geological formations like depleted oil and gas reservoirs, saline aquifers, coal seams, and enhanced oil recovery (EOR) sites. Opportunities include improved geochemical trapping of CO2, optimized storage capacity, improved sealing integrity, managed wellbore leakage risk, and use of sealant materials to reduce leakage risk. Furthermore, the potential impact of advancements in geochemical research, understanding geochemical reactions, addressing the challenges, and leveraging the opportunities in GCS are crucial for achieving sustainable carbon mitigation and combating global warming effectively. [ABSTRACT FROM AUTHOR]

In 1989, the first prolific hydrocarbon reservoirs were discovered by Saudi Aramco in the highly porous and permeable friable continental sandstones (Unayzah reservoirs) and shallow marine carbonates (Khuff reservoirs) of the Paleozoic successions in the south of Riyadh, central Arabia. Since 1989, Saudi Aramco has discovered new oil and gas fields in various stratigraphically and genetically different units of the Permo-Carboniferous and Permian successions. These successions were strongly affected by tectonic movements (Caledonian and Hercynian orogenesis) and Early and Late Paleozoic Gondwana glaciations. Therefore, the thickness of some sections was fully eroded or significantly reduced. The sequence stratigraphic interpretation of the Paleozoic successions allowed us to understand the depositional environments and regional distribution of the source, reservoir, and cap rock facies in improved palynologic studies. Hydrocarbons were discovered with the Late Permian continental sandstones of the Unayzah Formation, the glaciogenic sandstones of the Late Ordovician Sarah Formation in Saudi Arabia, Late Silurian Hazro reservoir in southeast Türkiye, and the cold desert eolian sandstones of the Permo-Carboniferous Haradh Formation. Potential source rock facies of the Qusaiba Shale Member in Saudi Arabia and the hot shale facies of the Dadaş Formation in southeast Türkiye were deposited at the base of the Early Silurian regional transgression (444 Ma) during the melting phase of the huge Gondwana ice mass. The hydrocarbons migrated downward into the glaciogenic reservoir sandstones due to the hydrostatic pressure provided a useful depositional environment model. The hydrocarbon discoveries have provided core and well log data for regional correlations. Every aspect of the sequence stratigraphy was investigated and various types of unconformities, sequence boundaries, glaciation periods, and maximum flooding surfaces were recognized and correlated between Middle East countries. The relationship between the sea-level fluctuations and sediment supply into the basin was established by the regressive (progradational) and transgressive parasequences and parasequence sets. This genetic sequence stratigraphic approach has significantly increased the hydrocarbon explorations and production in the entire Arabian Platform. [ABSTRACT FROM AUTHOR]

The safety of aquifer gas storage (AGS) depends on the mechanical stability of the caprock to a great extent. The injection and production operation of AGS will cause the disturbance of the in-situ stress due to the change of pore pressure in the reservoir and caprock, which may lead to the failure of caprock. The con AGS is established based on geological structure and hydrogeological information. By using the finite element method, the factors such as boundary condition, properties of reservoir and caprock, and in-situ stress coefficient are considered, respectively, and the variation of formation pressure and disturbed stress in the process of injection and production are analyzed. The results show that the boundary conditions are of significant influence on the stress field. The shear failure risk of reservoir–caprock interface under closed boundary is the greatest. The in-situ stress coefficient has the greatest influence on the failure risk of the caprock, followed by the permeability of the reservoir and caprock. [ABSTRACT FROM AUTHOR]

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

Safe and efficient underground storage of hydrogen requires cap rocks with effective sealing capabilities. This study investigates the interplay between various factors and their influence on hydrogen leakage from cap rocks. Compared to other commonly stored gases, hydrogen exhibits a significantly faster leakage rate. This study reveals that pore size and tortuosity of cap rocks play a crucial role. Larger pore sizes and lower tortuosity factors lead to increased leakage. Conversely, higher tortuosity (more twisted pores) enhances the sealing capability. Cap rocks with a tortuosity greater than 3 or an effective pore size below 5 nm demonstrated exceptional sealing capabilities. Beyond pore geometry, the study underscores the dependence of hydrogen diffusivity on prevailing underground conditions. Higher reservoir temperatures translate to a faster leakage rate, whereas increased pressure reduces the mean free path of hydrogen molecules, hindering diffusion and promoting retention within the storage formation. Reservoirs of temperature below 350 K and under a pressure exceeding 13.80MPa (2000 psi) exhibited minimal leakage. These findings underscore the crucial role of meticulous cap rock selection for safe and efficient underground hydrogen storage. This research paves the way for future investigations exploring the impact of additional factors such as the presence of other gases, the chemical composition of the cap rock itself, and the long-term effects of hydrogen exposure on cap rock integrity. A comprehensive understanding of these factors is essential for optimizing underground hydrogen storage strategies and ensuring long-term environmental sustainability. • Hydrogen could escape cap rocks faster than other gases like carbon dioxide and methane. • Cap rocks with pores larger than 5 nm leak hydrogen more readily. • Twisting, complex pores (tortuosity greater than 3) slow hydrogen escape. • Warmer underground storage of temperature greater than 350 K increases hydrogen loss. • Higher pressure than 2000 psi helps trap hydrogen by slowing its diffusion. [ABSTRACT FROM AUTHOR]

Regional mudstone cap rock has an important influence on the oil and gas distribution of the oil source faults below it. Therefore, studying the influence of these mudstone cap rocks on the hydrocarbon distribution pattern is fundamental to understanding the oil and gas distribution of the lower generation and upper reservoir reservoirs in the Bohai Bay Basin. This study classified two types of hydrocarbon diversion from oil source faults: blockage diversion and seepage diversion. To locate them, we established a method to predict the areas with blockage diversion and seepage diversion separately by superimposing the sealing and leakage parts of the regional mudstone cap rock with the regions of the connected distribution of sand bodies and the favorable hydrocarbon transport sites of the oil source faults, respectively. We used this approach to predict the locations where hydrocarbons are diverted by the oil source faults under the regional mudstone cap rocks in the first and second sections of the Dongying Formation (E3d1-2) in the Liuchu area of the Raoyang Sag, Bohai Bay Basin. The results show that the regional mudstone cap rock's blockage diversion occurs mainly in the south-central area of Liuchu, with a localized distribution in the northern part. The seepage diversion site is primarily located in the northeastern area and is also found locally in the west. Both diversions are beneficial for the accumulation of hydrocarbons from the source rocks of the first member of the Shahejie Formation (E3s1) to the upper second member of the Dongying Formation (E3d2U). The latter can also accumulate hydrocarbons in the Guantao Formation (N1g). The results align with the hydrocarbon distribution, demonstrating the feasibility of our method to predict various oil source fault diversion sites under the regional mudstone cap rock. This prediction method offers valuable guidance for exploring the lower generation and upper reservoir hydrocarbon accumulations in hydrocarbon-bearing basins. [ABSTRACT FROM AUTHOR]

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

Injection-induced seismicity and aseismic slip often involve the reactivation of long-dormant faults, which may have extremely low permeability prior to slip. In contrast, most previous models of fluid-driven aseismic slip have assumed linear pressure diffusion in a fault zone of constant permeability and porosity. Slip occurs within a frictional shear crack whose edge can either lag or lead pressure diffusion, depending on the dimensionless stress-injection parameter that quantifies the prestress and injection conditions. Here, we extend this foundational work by accounting for permeability enhancement and dilatancy, assumed to occur instantaneously upon the onset of slip. The fault zone ahead of the crack is assumed to be impermeable, so fluid flow and pressure diffusion are confined to the interior, slipped part of the crack. The confinement of flow increases the pressurization rate and reduction of fault strength, facilitating crack growth even for severely understressed faults. Suctions from dilatancy slow crack growth, preventing propagation beyond the hydraulic diffusion length. Our new two-dimensional and three-dimensional solutions can facilitate the interpretation of induced seismicity data sets. They are especially relevant for faults in initially low permeability formations, such as shale layers serving as caprock seals for geologic carbon storage, or for hydraulic stimulation of geothermal reservoirs. This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'. [ABSTRACT FROM AUTHOR]

Kerogen has a lower affinity to hydrogen than methane; thus, it allows hydrogen to flow more easily, but it is unclear how the permeabilities of hydrogen and methane differ. This study determines the single-phase permeability of hydrogen and compares it with methane permeability in organic-rich caprock. It takes into account adsorption to the pore wall and slippage at the boundary. It implements the two processes at 370 K for pressures from 500 to 4000 psi to obtain the hydraulic conductance of a sub-100-nm conduit. It then relates them to the macroscopic behavior via network modeling. Lower pressures represent depleted gas reservoirs in the subsurface. Decreasing pore pressure enhances hydrogen transport by reducing its adsorption to the pore wall and transitioning its behavior from continuum to discrete particles, leading to first- or second-order slippage. The results show that hydrogen conductance, q i n − s i t u (H 2), is always larger than the reference conductance without adsorption and slippage (q 0). Hydrogen permeability, k i n − s i t u (H 2), is also larger than methane permeability, k i n − s i t u (CH 4), while the permeability values differ by 70% − 130%, depending on the pore pressure. This study also determines the conduit size corresponding to the ratio of hydrogen permeability to methane permeability at in-situ conditions by comparing it with the ratio of hydraulic conductance of hydrogen to methane. The results have applications in underground hydrogen storage by indicating how hydrogen flow changes with pressure in ultra-tight formations. [Display omitted] • This study investigates H 2 permeability in organic-rich caprock in the subsurface. • It quantifies the effects of adsorption and slippage for H 2 in the nanosize conduit. • Slippage dominates H 2 flow, and the effects of adsorption are negligible. • H 2 conductance is higher than CH 4 conductance because H 2 adsorbs less to kerogen and slips more. • H 2 permeability is almost twice the CH 4 permeability in the organic-rich caprock. [ABSTRACT FROM AUTHOR]

This paper presents a comprehensive computational model for analyzing thermo‐hydro‐mechanical coupled processes in unsaturated porous media under frost actions. The model employs the finite element method to simulate multiphase fluid flows, heat transfer, phase change, and deformation behaviors. A new soil freezing characteristic curve model is proposed to consider the suctions from air‐water capillary pressure and water‐ice cryosuction. A total pore pressure with components from liquid water pressure, air pressure, and ice pressure is used in the effective stress law. Vapor and dry air are considered miscible gases, utilizing the ideal gas law and Dalton's law. The governing equations encompass the linear momentum balance equation, the energy balance equation, and mass conservation equations for water species (ice, liquid, and vapor) and dry air. Weak forms are formulated based on primary variables of displacement, water pressure, air pressure, and temperature. The spatial discretization is achieved through the finite element method, while temporal discretization employs the fully implicit finite difference method, resulting in a system of fully coupled nonlinear equations. To verify the proposed computational model, a numerical implementation is developed and validated against a set of experimental data from the literature. The successful verification demonstrates the robustness of the model. A detailed discussion of the contributions from phase change strain and different sources of pore pressure is also addressed. [ABSTRACT FROM AUTHOR]

The integrity of caprock sealing is a crucial factor in guaranteeing the safety and long-term feasibility of CO2 saline aquifer storage. In this study, we identified three principal mechanisms that give rise to topseal failure: (1) gradual CO2 seepage through the upper cap, (2) capillary seal failure resulting from the pressure increment due to CO2 injection, and (3) localized overpressure causing cap rupture. Through the integration of numerical simulation and geomechanics, this study offers a sealing assessment for the caprock. The thorough analysis of the sealing performance of the Guantao formation reveals that after 2000 years of CO2 injection, the caprock would undergo intrusion by 35 m without any leakage risk. Moreover, investigations into CO2–water–rock interactions suggest that precipitation reactions outweigh dissolution reactions, leading to a decreased permeability and an enhanced sealing performance. The most likely fracture mode identified is shear fracture with a critical caprock fracture pressure of 36.48 MPa. In addition to these discoveries, it is significant to consider ongoing research aimed at enhancing our ability to predict and manage potential risks associated with carbon capture and storage technologies. [ABSTRACT FROM AUTHOR]

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

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

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

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels. [ABSTRACT FROM AUTHOR]

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

Subsurface natural hydrogen accumulations that can be economically and safely recovered are a major target of the present roadmap towards the use of hydrogen as an alternative and C-free energy resource. The existence of H 2 -rich reservoirs in ophiolites, where H 2 is produced via serpentinization, was theoretically predicted based on the intensity of gas seeps in Turkey and Albania. Here, we examine the geological bases supporting the potential existence of H 2 reservoirs within ophiolites in general, also considering available data on ophiolitic petroleum reservoirs, and we document a direct observation of a H 2 -rich accumulation within an ophiolite. We studied the case of a borehole, drilled in the 1970s for metal mining exploration purposes within the Tișovița–Iuți ophiolite, in Romania, which accidentally encountered pressurized gas with ∼29 vol% H 2 at a depth of about 800 m. We reconstructed the geometry of the ophiolite sequence in correspondence with the well and suggested that the reservoir is within cataclastic dunite near the tectonic contact between layered dunite and the harzburgite-dunite peridotites; the upper, non deformed portion of serpentinized layered dunite, likely with the contribution of tonalite veins, acted as a fluid trap. Although plugged, we detected H 2 leakage from this well and from a second well in the same area, with H 2 concentrations exceeding 100 ppmv in the air and 0.1 mg H 2 /L in the water within the wellhead open casing. We propose a broad conceptual model in which deformed, fractured, and non-deformed, impermeable sections of serpentinized peridotites can determine ophiolitic H 2 -rich reservoirs and traps, respectively, as factors that shall be considered in the guidelines for H 2 reservoir exploration. • Direct observation of pressurized H 2 -rich reservoir in ophiolite (Romania). • Potential reservoirs and cap rocks in ophiolites. • H 2 leakage observed in the abandoned wells. [ABSTRACT FROM AUTHOR]

On the basis of "Carbon Peak and Carbon Neutral" goals, carbon sequestration projects are increasing in China. The integrity of cement sheaths, as an important factor affecting carbon sequestration projects, has also received more attention and research. When CO2 is injected into the subsurface from sequestration wells, the cement sheath may mechanically fail due to the pressure accumulated inside the casing, which leads to the sealing of the cement sheath failing. The elasticity and strength parameters of the cement sheath are considered in this paper. The critical bottom-hole injection pressures of inclined well sections under anisotropic formation stresses at different depths were calculated for actual carbon-sealing wells in the X block—the CO2 sequestration target block. The sensitivity factors of the critical bottom-hole injection pressure were also analyzed. It was found that the cement sheath damage criterion was tensile damage. The Young's modulus and tensile strength of the cement sheath are the main factors affecting the mechanical failure of the cement sheath, with Poisson's ratio having the second highest influence. An increase in the Young's modulus, Poisson's ratio, and tensile strength of the cement sheath can help to improve the mechanical stability of cement sheaths in CO2 sequestration wells. This model can be used for the design and evaluation of cement in carbon sequestration wells. [ABSTRACT FROM AUTHOR]

In this paper, we use a new workflow to substantiate the characterization of a prominent, deep sediment conductor in the hyperextended Bjørnøya Basin (SW Barents Sea) previously identified in smooth resistivity models from 3-D deterministic inversion of magnetotelluric data. In low-dimensionality environments like layered sedimentary basin, 1-D Bayesian inversion can be advantageous for a thorough exploration of the solution space, but the violation of the 1-D assumption has to be efficiently handled. The primary geological objectives of this work is therefore preceded by a secondary task: the application of a new machine learning approach for handling the 1-D violation assumption for 21 MT field stations in the Barents Sea. We find that a decision tree can adequately learn the relationship between MT dimensionality parameters and the 1-D–3-D residual response for a training set of synthetic models, mimicking typical resistivity structures of the SW Barents Sea. The machine learning model is then used to predict the dimensionality compensation error for MT signal periods ranging of 1–3000 s for 21 receivers located over the Bjørnøya Basin and Veslemøy High. After running 1-D Bayesian inversion, we generated a posterior resistivity distribution for an ensemble of 6000 1-D models fitting the compensated MT data for each 21 field stations. The proportion of 1-D models showing ρ < 1 Ω·m is consistently beyond 80 per cent and systemically reaches a maximum of 100 per cent in the Early Aptian–Albian interval in the Bjørnøya Basin. In hyperextended basins of the SW Barents Sea, the dimensionality compensation workflow has permitted to refine the characterization of the deep basin conductor by leveraging the increased vertical resolution and optimal used of MT data. In comparison, the smooth 3-D deterministic models only poorly constrained depth and lateral extent of the basin anomaly. The highest probability of finding ρ < 1 Ω·m is robustly assigned to the syn-tectonic Early Aptian–Albian marine shales, now buried at 6–8 km depth. Based on a theoretical two phase fluid-rock model, we show that the pore fluid of these marine shales must have a higher salinity than seawater to explain the anomaly ρ < 1 Ω·m. Therefore, the primary pore fluid underwent mixing with a secondary brine during rifting. Using analogue rift systems in palaeomargins, we argue that two possible secondary brine reservoir may contribute to deep saline fluid circulation in the hyperextended basin: (1) Permian salt-derived fluid and, (2) mantle-reacted fluid from serpentinization. [ABSTRACT FROM AUTHOR]

Evaluating underground gas storage (UGS) sealing capacity is essential for its safe construction and operational efficiency. This involves evaluating both the static sealing capacity of traps during hydrocarbon accumulation and the dynamic sealing capacity of UGS under intensive gas injection and withdrawal, and alternating loads. This study detailed the methodology developed by Sinopec. The approach merges disciplines like geology, geomechanics, and hydrodynamics, employing both dynamic-static and qualitative-quantitative analyses. Sinopec's evaluation methods, grounded in the in situ stress analysis, include mechanistic studies, laboratory tests, geological surveys, stress analysis, and fluid-solid interactions. Through tests on the static and dynamic sealing capacity of UGS, alongside investigations into sealing mechanisms and the geological and geomechanical properties of cap rocks and faults, A geomechanics - rock damage - seepage mechanics dynamic coupling analysis method has been developed to predict in situ stress variations relative to pore pressure changes during UGS operations and evaluate fault sealing capacity and cap rock integrity, thereby setting the maximum operational pressures. Utilizing this evaluation technique, Sinopec has defined performance metrics and criteria for evaluating the sealing capacity of depleted gas reservoirs, enabling preliminary sealing capacity evaluations at UGS sites. These evaluations have significantly informed the design of UGS construction schemes and the evaluation of fault sealing capacity and cap rock integrity during UGS operations. [ABSTRACT FROM AUTHOR]

Petrophysical parameters were assessed using comprehensive log data coming from two wells (Ns-2, Ns-4) located within the Mishrif, Rumaila, Ahmadi, and Mauddud formations within the Nasiriya oil field, Iraq. The logs were digitized using Techlog 2015 software, and environmental modifications were implemented to guarantee precise interpretations. The shale volume used to be determined using gamma ray (GR) logs, subsequently leading towards the calculation of the effectiveness porosity. Water saturation is used to be calculated alongside Archie's equation. The investigation indicated that the lithology regarding the Mishrif, Rumaila, Ahmadi, and Mauddud formations happens to be predominantly limestone, alongside calcite like the principal mineral within the matrix. All formations were found to contain water like the fluid type, except within favor regarding the Mishrif formation at the 2013–2046 m within Ns-2, and 2000–2060 m within Ns-4, where hydrocarbons were identified. The top strata for these depths comprise substantial shale alongside limited effective porosity, serving like cap rock at the depths from 2013 to 2016 m within Ns-2, and 2000 towards 2006 m within Ns-4. [ABSTRACT FROM AUTHOR]

Water-soluble mining was invariably associated with surface subsidence, which in some cases escalated to the movement, deformation, and even collapse of the overlying rock layers, triggering grave subsidence calamities. The caprock of the salt-bearing strata in the Longgui salt rock mining area was closely adjacent to the third aquifer, which mainly consisted of fractured, porous, high-permeability materials such as mudstone conglomerates, rendering the geological conditions highly complex. Years of water-soluble mining had led to significant surface subsidence in the mining area, with a trend toward accelerated subsidence. In this study, the geological conditions of the Longgui salt rock mining area were analyzed, and through simulated experiments of pillar dissolution mining, the mechanisms of surface subsidence in the area were examined. Over time, the dissolution gradually perforated the pillars and caprock, with the pillars ceasing to support the caprock, ultimately transforming small cavities into a large single cavity. Utilizing subsidence data, this research employed numerical simulation to inverse and predict subsidence patterns from 2019 to 2025, revealing that the maximum subsidence reached 1367.6 mm in mining area I and 1879.5 mm in mining area II, with subsidence rates of 12.05 mm/y and 44.78 mm/y, respectively. Moreover, the impact of ground subsidence on the construction of adjacent subways was assessed by establishing monitoring points and evaluating subsidence along subway cross-sections and longitudinal directions. The findings provided valuable insights for guiding the prevention and control of surface subsidence calamities in the Longgui salt rock mine and similar mining areas in Guangzhou, China. [ABSTRACT FROM AUTHOR]

Microbial grouting technology based on microbially induced calcite precipitation (MICP) is a new soil improvement method. This technique involves injecting bacteria and a cementation solution into soil pores to generate CaCO3 precipitation, thereby enhancing soil strength. Studies on microbial grouting from the aspects of experimental studies, theoretical models and engineering applications were extensively reviewed. Factors such as grouting methods, grouting rate, cementation solution concentration, and pH significantly influence the size and distribution of CaCO3. The three-phase grouting method enhances bacterial adsorption and soil strength. The higher grouting rate (grouting rate greater than reaction rate) and low pH (pH is not lower than 4) facilitate the uniform distribution of CaCO3. The size of CaCO3 and the soil strength increase with increasing cementation solution concentration. The existing models were established based on equilibrium flow, which overlooks the reduction of solute migration distance caused by the non-uniformity of the medium. Micro-structural analysis shows that CaCO3 precipitation between adjacent soil particles acts as a matrix supporting to increase soil strength. Microbial grouting technology can employ CaCO3 precipitation to seal wellbore cracks for CO2 storage and cement soil particles for slope stability and foundation improvement. Finally, the challenges encountered in microbial grouting technology were discussed. [ABSTRACT FROM AUTHOR]

Deep coalbed methane (DCBM) reservoirs hold exceptional potential for diversifying energy sources. The Ordos Basin has attracted much attention due to its enormous resource reserves of DCBM. This work focuses on the Jiaxian area of the Ordos basin, and the multi-factor quantitative evaluation method on the sealing of cap rocks is established. The abundant geologic and reservoir information is synthesized to explore variable factors affecting the gas content. Results indicate that the sealing capacity of the coal seam roof in the Jiaxian area, with a mean sealing index of 3.12, surpasses the floor's sealing capacity by 13.87%, which averages 2.74. The sealing of the coal seam roof has a more positive impact on the enrichment of coalbed methane (CBM). In addition, the conditions for preserving gas would be boosted as coal seam thickness increased, leading to enhanced gas content in coal seams. The CH4 content increases by an average of ~2.38 m3/t as coal seam thickness increases with the interval of 1 m. The increasing burial depth represents the incremental maturity of organic matter and the gas generation ability in coal seams, which contributes to improving the gas content in coal seams. There is a positive correlation between the degree of coal fragmentation and the gas content of the coal seam to a certain extent. These findings provide valuable insights for targeted drilling strategies and enhancing natural gas production capacity in the Jiaxian area of the Ordos Basin. [ABSTRACT FROM AUTHOR]

Field and petrographic studies of the Qishn Formation provide insights in to sequence stratigraphic and reservoir attributes of the formation. The reservoir properties are controlled by complex interaction between depositional textures and diagenetic products. The Barremian-Aptian Qishn Formation was deposited between Precambrian basement rocks and marl-dominated Albian Kharfort Formation. The Qishn Formation consists of lower sandstone (Shabon Member), middle unit dominated by lime mudstone (Hinna Member), and upper bioclastic limestone with dolostone interbeds (Hasheer Member). The formation defines a transgressive-regressive sequence with maximum flooding surface (MFS) at the top of the Hinna Member. The petrographic and diagenetic analyses indicate that Shabon and Hasheer members constitute good reservoirs. The Shabon Member is dominated by friable medium- to coarse-grained arkose to lithic arenite with porosity as high as 20%. Despite a burial depth of ~ 5 km, the sandstone maintains most of its intergranular pores. The diagenetic features include early calcite cement followed by burial compaction. However, since most of the pores were already filled by calcite cement, volumetric reduction due to compaction was minimal. Post-compaction dissolution of the early calcite cement resulted in restoration of the intergranular pores. The Hasheer Member consists of extensively cemented bioclastic packstone to rudstone with porosity < 6% and sucrosic dolomite with intercrystalline and vuggy pores reaching up to 15%. The mud-dominated Hinna Member can be considered as potential cap rock for any fluids within the Shabon Member, whereas the marls of the Kharfot Formation constitute potential caprock for the preservation of fluids in the Hasheer Member. [ABSTRACT FROM AUTHOR]

Featured Application: This study emphasizes the importance of comprehensive monitoring, calibration, and optimization of storage strategies in a saline aquifer. It also highlights the need to manage geomechanical risks and uncertainties. By understanding these risks and employing suitable monitoring techniques, the integrity and safety of GCS can be ensured, contributing to the reduction of CO2 emissions. Geological Carbon Storage (GCS) involves storing CO2 emissions in geological formations, where safe containment is challenged by structural and stratigraphic trapping and caprock integrity. This study investigates flow and geomechanical responses to CO2 injection based on a Brazilian offshore reservoir model, highlighting the critical interplay between rock properties, injection rates, pressure changes, and ground displacements. The findings indicate centimeter-scale ground uplift and question the conventional selection of the wellhead as a monitoring site, as it might not be optimal due to the reservoir's complexity and the nature of the injection process. This study addresses the importance of comprehensive sensitivity analyses on geomechanical properties and injection rates for advancing GCS by improving monitoring strategies and risk management. Furthermore, this study explores the geomechanical effects of modeling flow in the caprock, highlighting the role of pressure dissipation within the caprock. These insights are vital for advancing the design of monitoring strategies, enhancing the predictive accuracy of models, and effectively managing geomechanical risks, thus ensuring the success of GCS initiatives. [ABSTRACT FROM AUTHOR]

In the deep Longmaxi Formation shale gas reservoirs of the southern Sichuan Basin, strong overpressure is universally developed to varying degrees. However, there is currently a lack of in-depth research on the formation mechanisms, evolutionary patterns, and the controlling effects on reservoir pore characteristics of strong overpressure. This limitation significantly restricts the evaluation of deep shale gas reservoirs. This study selected typical overpressured shale gas wells in Yongchuan, Luzhou, and Dazu areas as research subjects. Through comprehensive methods such as log analysis, fluid inclusion analysis, and numerical simulation, the dominant mechanisms of strong overpressure formation were determined, and the pressure evolution from early burial to late strong uplift was characterized. Additionally, the impact of varying degrees of overpressure on reservoir pore characteristics was studied using techniques such as scanning electron microscopy, gas adsorption-mercury intrusion, and helium porosity testing. The research findings indicate that hydrocarbon generation expansion is the primary mechanism for strong overpressure formation. The pressure evolution in the early burial phase is controlled by the processes of kerogen oil generation and residual oil cracking into gas. The reservoir experienced three stages: normal pressure (Ordovician to Early Triassic), overpressure (Early Triassic to Early Jurassic), and strong overpressure (Early Jurassic to Late Cretaceous), with pressure coefficients of approximately 1.08, 1.56, and 2.09, respectively. During the late strong uplift phase, the adjustment of early overpressure occurred due to temperature decrease and gas escape, leading to a decrease in formation pressure from 140.55 MPa to 81.63 MPa, while still maintaining a state of strong overpressure. Different degrees of strong overpressure exert a significant control on the physical properties of shale reservoirs and the composition of organic matter pores. Variations exist in the organic matter pore morphology, structure, and connectivity within the deep Wufeng-Longmaxi shale. Higher overpressure favors the preservation of organic large pores and reservoir porosity. Under conditions of strong overpressure development, deep siliceous shales and organically rich clay shales exhibit favorable reservoir properties. By determining the dominant mechanisms of strong overpressure in the Wufeng-Longmaxi Formation and studying pore characteristics, this research not only deepens the understanding of the geological features of deep shale gas reservoirs but also provides a new perspective for understanding the overpressure mechanisms and reservoir properties of deep shale gas reservoirs. Moreover, it is of significant importance for guiding the exploration and development of deep Longmaxi shale and provides valuable references for further research in related fields. [ABSTRACT FROM AUTHOR]

Carbon geological storage (CGS) is one of the key processes in carbon capture and storage (CCS) technologies, which are used to reduce CO2 emissions and achieve carbon-neutrality and net-zero emissions in developing countries. In Thailand, the Mae Moh basin is a potential site for implementing CGS due to the presence of a structural trap that can seal the CO2 storage formation. However, the cost of CGS projects needs to be subsidized by selling carbon credits in order to reach the project breakeven. Therefore, this paper estimates the economic components of a CGS project in the Mae Moh basin by designing the well completion and operating parameters for CO2 injection. The capital costs and operating costs of the process components were calculated, and the minimum carbon credit cost required to cover the total costs of the CGS project was determined. The results indicate that the designed system proposes an operating gas injection rate of 1.454 MMscf/day, which is equivalent to 29,530 tCO2e per year per well. Additionally, the minimum carbon credit cost was estimated to be USD 70.77 per tCO2e in order to achieve breakeven for the best case CGS project, which was found to be much higher than the current market price of carbon credit in Thailand, at around USD 3.5 per tCO2e. To enhance the economic prospects of this area, it is imperative to promote a policy of improving the cost of carbon credit for CGS projects in Thailand. [ABSTRACT FROM AUTHOR]

To prevent or reduce the loss caused by land subsidence in delta region, the land subsidence of the Zhuangxi–Wuhaozhuang oil area in Shengli Oilfield is predicted based on the elastic theory of porous medium and classical consolidation theory, and the prediction results are analyzed and verified by numerical simulation. The influencing factors and mechanism of land subsidence in delta resource exploitation area are studied. The research shows that: (1) the land subsidence in delta resource exploitation area is mainly caused by the underground brine exploitation, oil exploitation, consolidation of loose sediments, shallow groundwater exploitation, and soil load consolidation. The maximum land subsidence rate obtained by numerical simulation is 22 mm/a for single oil well and 81 mm/a for single brine well. (2) Pore pressure, physical and mechanical parameters of oil and brine reservoirs, development mode, and development degree are influencing factors of land subsidence in delta resource exploitation area, and pore pressure, permeability, and reservoir burial depth are controlling factors. (3) The exploitation wells in the Zhuangxi–Wuhaozhuang oil area are dense, and the influence range of land subsidence of different exploitation wells overlaps, which further aggravates the uneven land subsidence, and makes the result of InSAR subsidence monitoring larger. [ABSTRACT FROM AUTHOR]

Integrity of fault and top seal is a key factor that affects hydrocarbon fluid phase distribution in the subsurface. Mapping fluid property distribution can therefore provide important tools towards assessing seal integrity and trapping mechanisms – two of the most critical elements in petroleum systems analysis towards optimzing exploration and development strategies. This is best achieved by proper fluid characterization that integrates fluid geochemistry and pressure–volume–temperature (PVT) data to identify equilibrated and disequilibrated fluid gradients. Fields from Paleozoic and Mesozoic basins in the Arabian Peninsula at different stages of delineation, appraisal, development and management are discussed as examples to demonstrate the role of fluid characterization in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on trapping mechanism, fluid distribution and flow capacity. Examples discussed include (1) reservoir heterogeneity controlling fluid distribution and trapping mechanisms in two neighbouring gas fields, (2) geochemical evidence for a lateral seal separating gas condensate region from oil discovered during field development, (3) solid reservoir bitumen atop a giant gas field, (4) selective gas leakage through anhydrite seal, and (5) geochemical evidence for fault-controlled reservoir compartmentalization rather than a hydrodynamically tilted fluid contact in a field at an appraisal stage where PVT data are limited or inconclusive. Put in structural context, seal-related interpretations of the fluid data are aligned with observations from seismic and geological data on the existence of faults with favourable orientations or facies changes. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022 [ABSTRACT FROM AUTHOR]

The planned pilot CO2 storage Zar-3 is an oil field with a gas cap in the final production stage in the SE Czech Republic. It is composed of a dolomite Jurassic reservoir sealed by three different formations that differ significantly in lithology. Previous studies left open questions on the nature of pore space and connectivity and the quality of the seal in the future CO2 storage complex. Microscopic petrography of the reservoir suggests dolomitisation in shallow water followed by karstification and brecciation with fracture-correct-dominated porosity. The seal horizons have porosity limited to the micro- and nanoscales. The oil consists of significantly biodegraded black oil of Jurassic origin mixed with less biodegraded gasoline-range hydrocarbons. Biomarkers in the caprock bitumens trapped in nanopores show a genetic relationship to the reservoir oil. Gas in the not yet fully depleted gas cap of the field is of thermogenic origin with no contribution of microbial methane. The formation water has total dissolved solids typical of isolated brines not diluted by infiltrated fresh water. The geochemical characteristics of the storage system together with the fact that the initial oil column is about 105 m tall with another 150 m of gas cap suggest that the seals are efficient and the Zar-3 future storage complex is tight and safe. [ABSTRACT FROM AUTHOR]

Selection of the proper underground hydrogen storage (UHS) site is an essential issue for zero-emission systems based on renewables. The article presents the method for assessing storage traps in saline aquifers and the ranking of storage traps in saline aquifers from the Polish Lowlands for UHS. The ranking was based on the multi-criteria approach of the hierarchical analysis of the decision-making process. The best UHS site was determined based on geological and reservoir criteria. The criteria weights were evaluated using two methods for comparative purposes. The parameters of individual storage traps came from the database developed in the Hystories project. The highest positions in the ranking were obtained by storage traps characterized by the best sealing parameters of caprock, lack of faults within the traps, and good permeability of the reservoir layers. The presented ranking approach can support the decision-making process for selecting UHS sites in other countries. • Multi-criteria decision analysis was used to develop the ranking of storage traps. • The method was applied for pre-selection of UHS sites in deep aquifers in Poland. • The workflow was developed for the ranking of storage traps in deep aquifers. • The role of criteria weights in the ranking of storage traps was presented. • The method can be used for pre-selection of storage traps in aquifers worldwide. [ABSTRACT FROM AUTHOR]

Croatia has both significant CO2 emissions from the point sources and a history of oil and gas exploration, and this is why the CCS technology surfaced as a viable solution for curbing CO2 emissions on a national level. Since approximately half of emissions from the stationary industrial sources occur along the Adriatic coastline, the entire offshore area became an exploration target. Regional studies revealed the potential storage plays, one of which is in the aquifer of the Mesozoic carbonate complex with dual porosity extending all along the Croatian offshore area. Three structures were chosen in its central part–Klara, Kate and Perina. For the first two, the models were constructed based on the data from old exploration wells and a regional structural map, while for the Perina structure, a new seismic interpretation was added to better characterise its properties. It came out that the Kate structure appears to be the most prospective in general (45 Mt), with neighbouring Klara as the second (39 Mt), while the initially promising Perina (7 Mt) turned out to be of far lesser importance. The Perina structure case is an example that new seismic interpretation can reduce the capacity estimate if it reveals certain limiting factors, in this case, the limitation of structural closure. [ABSTRACT FROM AUTHOR]

This study underscores the critical role of carbon capture and storage (CCS) in mitigating greenhouse gas emissions and addresses the potential for CCS projects in saline aquifers in Brazil, one of the world's largest carbon emitters. The country's ability to adopt CCS is significantly influenced by the availability of data related to regional CO2 storage potential and identifying suitable geological framework for CO2 injection. While oil and gas reservoirs have traditionally been prioritized, saline aquifers represent an underexplored and potentially higher capacity storage option. Despite Brazil's 31 sedimentary basins, the data quantity and availability for these contexts remain insufficient for advanced studies on the geological storage of CO2 considering saline aquifers. An initial study was conducted indicating five potential targets in the Paraná and Potiguar Basins for geological storage in saline aquifers based on available public data, mainly drilling data. This review reveals substantial challenges related to the evaluation of Brazil's CO2 storage capacity, such as the lack of modern seismic studies, the absence of a regulatory framework for CO2 storage, and insufficient investment in new well exploration. These challenges necessitate multistakeholder collaboration, the development of a supportive regulatory environment, and investment in extensive site characterization campaigns. Addressing these barriers is fundamental to realizing the country's CCS potential and contributing to global decarbonization efforts. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Porous sandstone geothermal water is an important geothermal resource, which is a low-carbon and clean resource, but lacks systematic research on a regional scale. The northern part of Jinan City is rich in geothermal resources, specifically porous sandstone thermal reservoirs. However, there is still incomplete research on the mechanism of geothermal genesis and the hydrochemical characteristics of geothermal water in porous sandstone. This study aims to address this gap by collecting 21 groundwater samples from northern Jinan and comparing their conventional ion and isotope characteristics to investigate the hydrochemical characteristics during the formation of geothermal water and uncover the genesis mechanism of porous sandstone geothermal water. The results indicate that the geothermal water is classified as Na-Cl type and Na-SO4-Cl type. The hydrochemical characteristics of geothermal water are primarily influenced by water–rock interaction and groundwater mixing. The water source primarily comes from the atmospheric precipitation in the Taiyi mountains, with an altitude of 910.75–1542.2 m.s.a.l.. The estimated temperature of the thermal reservoir ranges from 51 to 78 °C, and the depth of geothermal water circulation is estimated to be between 1316 and 2216 m. Based on the characteristics of the geothermal field, including the "cap rock, water source, heat source, reservoir, and channel," a conceptual model of the porous sandstone geothermal water flow system is proposed. This model offers novel insights into the genesis mechanism of geothermal water under similar geological conditions. [ABSTRACT FROM AUTHOR]

Introduction: Carbon dioxide (CO2) enhanced gas recovery represents a viable strategy for sequestering CO2 while concurrently augmenting gas production from subsurface reservoirs. Gas reservoirs, as inherent geological formations, are optimal repositories for gaseous compounds, rendering them suitable for CO2 storage. Nevertheless, the economic viability of pure CO2 storage necessitates integration with oil and gas recovery mechanisms to facilitate widespread CO2 utilization. Method: This study addresses the complexities of CO2 enhanced gas recovery through a comprehensive approach that combines theoretical model and numerical simulations. A numerical model is developed to simulate three-component diffusion involving CO2, and methane (CH4) in a two-phase system comprising gas and water. Results: The investigation systematically explores the process of enhanced CH4 extraction and CO2 injection into the reservoir and examines the influencing factors on extraction. Simulation results reveal a power-law decrease in CH4 production rate, stabilizing at a constant extraction rate. Enhanced CH4 extraction benefits from increased porosity, with higher porosity levels leading to greater CH4 extraction. Permeability augmentation positively influences CH4 production, although with diminishing returns beyond a certain threshold. The CO2 injection rate shows a direct proportionality to CH4 production. However, elevated CO2 injection rates may increase reservoir pressure, potentially causing cap rock damage and CO2 gas flushing. Discussion: This study contributes valuable theoretical insights to the field of CO2 enhanced gas recovery engineering, shedding light on the intricate dynamics of multi-component fluid transport processes and their implications for sustainable CO2 utilization. [ABSTRACT FROM AUTHOR]

Thermal pressurization of the trapped pore fluid is considered to be a widespread fault weakening during fluid injection in confined geological formations. Tremendous amounts of heats will be generated within the narrow shear zone during fault slip. Considering the melting of the fault gouge, the fault seal zone is adopted to construct the fluid pressurization model, thermal pressurization implemented in Comsol Multiphysics is established to illustrate the fault weaken coefficient and effective normal stress during fluid injection. The friction weakening coefficients mT and mF are proposed to research the performance of fault weakening during fluid injection. The results indicate that, the friction coefficients mT and mF both exhibit the initially decreasing and then increasing tendency, and thermal-induced fault weakening of CO2 injection occurs earlier than that of water injection. It was found that initial pore pressure and fault sealing porosity have a negligible influence on the evolutions of friction weakening and effective normal stress. Initial normal stress and fault sealing permeability have certain obvious influences on fault weakening during CO2 injection. Fault thickness is the primary factor influencing the friction weakening coefficient. When the fault thickness is over 1 mm, the variation of fault weakening is totally different from that when the thickness is less than 1 mm. This investigation of friction weakening during fault slip provides an effective reference for fluid injection. [ABSTRACT FROM AUTHOR]

Achieving the nationally and internationally defined climate policy goals regarding the reduction of anthropogenically emitted greenhouse gas concentrations in the atmosphere is an enormous challenge. To this end, it can be assumed that underground storage of >100 billion tons of CO2 by the end of the century is necessary, as the capacity of natural storage (e.g. forestation, wetland restoration, oceanic CO2-sinks, biochar and soil carbon sequestration) is restricted, the permanent removal of CO2 from the atmosphere through carbon capture and use (CCU) is limited by the product lifetime. At the same time emissions cannot be curbed quickly enough. The principles of carbon capture and storage (CCS) have been researched internationally, the potential storage volumes have been determined and the feasibility of geological storage has been demonstrated by successful projects (e.g. the first European onshore pilot plant Ketzin in Brandenburg, commercial plant Sleipner in Norway, etc.). Neighbouring countries such as Norway, Denmark, UK and the Netherlands are going further and implement projects. Germany has the technical and scientific potential to realise the commercial implementation of CCS in Germany and could thus make a significant national contribution to climate policy goals. [ABSTRACT FROM AUTHOR]

The Campi Flegrei caldera is characterized by the phenomenon of bradyseism, as evidenced by stratigraphic records of alternate oceanic and continental sediments dating back over a thousand years. Since 2005, the caldera has been in a phase of unrest, which is increasing volcanic deformations and associated seismicity around the region, resulting in a growing concern over the dense population in the inhabitation. Recent studies have highlighted that the caldera dynamics are driven by a combination of endogenous processes and modulation phenomena induced by exogenous processes, e.g., rainfall, atmospheric pressure, and tidal loading. Although the complex feedback mechanisms of both endogenous and exogenous processes are still under debate, the present study is focused on the increased potential of modulation due to exogenous processes with the increase or evolution in the degree of inflation of the magma chamber. Specifically, Campi Flegrei volcanic system shows sensitivity to seasonal hydrological cycles during slower rates of inflation and to short-period tidal modulations during higher rates of inflation. The observed seasonal modulations of seismic activity are explained in terms of water infiltration into the shallow aquifers, basins, and vent depression system of the caldera. The rainfall-induced pore pressure build-up also favours the instability of the brittle cap rock, promoting seismicity. In addition, this study suggests that the tidal loadings provide horizontal NS extensions to the mostly NW–SE, NE–SW, and EW-oriented scattered fractures and further contribute towards fracture propagation. During this process, a cyclic opening and sealing of fractures by volatile outgassing and silicate settling may, respectively, produce the episodic behaviour of the seismicity. The seismicity in relation to exogenous processes imposed by seasonal rainfall and tidal loadings shows that the degree of correlation depends on the different rates of inflation. The long-period seasonal modulations and short-period tidal modulations during the evolution of the degree of inflation are finally interpreted in the framework of the fault resonance destabilization model, under rate-and-state dependant frictional formalism. [ABSTRACT FROM AUTHOR]

Whether from the near-surface or at great depths, geothermal energy aims to harness the heat of the Earth to produce energy. Herein, emphasis is put on geothermal reservoirs and their cap rock in crystalline rocks, in particular, the basements of sedimentary basins and volcanic islands in the context of subduction. This study is based on a case study of three examples from around the world. The aim of this paper is to show how the study of newly formed minerals can help the exploration of geothermal reservoirs. The key parameters to define are the temperature (maximum temperature reached formerly), fluid pathways, and the duration of geothermal events. To define these parameters, numerous methods are used, including optical and electronic microscopy, X-ray diffraction, microthermometry on fluid inclusions, chlorite geothermometry, and geochemistry analysis, including that of isotopes. The key minerals that are studied herein are phyllosilicates and, in particular, clay minerals, quartz, and carbonates. They are formed because of hydrothermal alterations in fracture networks. These minerals can have temperatures of up to 300 °C (and they can cool down to 50 °C), and sometimes, they allow for one to estimate the cooling rate (e.g., 150 °C/200 ka). The duration of a hydrothermal event (e.g., at least 63 Ma or 650 ka, depending on the site) can also be established based on phyllosilicates. [ABSTRACT FROM AUTHOR]

Hydrocarbon enrichment in faulted basins is often controlled by the activity of faults with some degree of sealing capacity. However, the rules that control the migration and accumulation of hydrocarbons in reservoirs dominated by faults are poorly understood. The Liuzhuang fault in the Bohai Bay Basin is selected for hydrocarbon migration and accumulation research. Interpretation of seismic and log data, tests of rock mechanics, and quantitative fluorescence analysis are used to quantitatively evaluate the migration of hydrocarbons. The results reveal that the Liuzhuang fault has been a long-term active fault since the Cenozoic with gradually reduced fault activity from the NE to the SW. At least four fault-bounded traps with various degrees of trap filling in the lower segment of the first member of Shahejie Formation (Es1L) were identified in the hanging wall of this fault. This differences in the degree of filling are related to the continuity of the smear structure that formed from the Es1m cap rock in the brittle‒ductile transition stage. The development degree of the smear structure, which is quantitatively evaluated by the shale smear factor (SSF) and shale gouge ratio (SGR), directly affected the fault sealing capacity. Therefore, three cases of hydrocarbon migration and accumulation, i.e., continuous smearing along the fault and complete fault sealing with SSF values of < 3, reduced continuity of the smear structure and partial fault sealing with SSF values in the range of 3–5, and discontinuous smearing and ineffective fault sealing with SSF values of > 5, were defined. The new results have implications for further exploration in faulted basins, including the Bohai Bay Basin. [ABSTRACT FROM AUTHOR]

Cross-borehole electrical resistivity tomography (CHERT) technology has been implemented in field-scale CCS/CCUS (carbon capture and storage/carbon capture, utilization and storage) projects. It is highly desirable to investigate how to optimize the design of the ERT electrode arrays and corresponding working schemes for both laboratory experiments and field applications. A CHERT system was developed for laboratory experiments of CO2 geological storage applications. An optimization method was established for optimizing the structure of electrode arrays and corresponding working schemes. The developed CHERT system was calibrated systematically to determine the measurement range and accuracy of electrical impedance. Laboratory experiments were designed and implemented to validate the performance of the developed CHERT system. It has been illustrated that: (1) It is an essential step to optimize the structure of electrode arrays and corresponding working schemes of CHERT according to the real application background. The optimization method based on finite-element modelling provides an effective means for designing a field-scale CHERT system. (2) The quality of the images inverted from the CHERT data is highly dependent on the working schemes and specific modes, which is closely related to the size of the data sets used for the inversion. The AM-BN scheme is recommended due to the better uniformity of the resultant sensitivity field and application to larger borehole spacing. (3) Based on the calibration, the measurement range of the developed CHERT system can be determined as 100 Ω to 4.5 kΩ with an error limit of 1.5%. The maximum relative errors of the impedance magnitude and phase angle are 5.0% and 7.0%, respectively. Based on the test results the location of the CO2-bearing objects can be identified accurately. The shapes of the tested objects present distortion to some extent, but this can be alleviated by selecting working modes with a larger size of data set. [ABSTRACT FROM AUTHOR]

Geologic carbon sequestration requires CO2 injection into the storage formation at high‐injecting pressure. Such high pressure could induce choked flow accompanying huge variations in thermodynamic properties of CO2 at a converging‐diverging (CD) fractures in the storage formation. In this study, high‐velocity CO2 transport through CD fractures was investigated to quantify the effect of fracture morphology on occurrence of both choked flow and shockwave that constrain the mass flow rate of fluid. In addition, variations in thermodynamic CO2 properties including Mach Number (Ma), defined by the ratio of fluid velocity to sound speed, and shock properties were investigated. The morphological characteristics of CD fractures were determined by nine properties, such as throat diameter, throat length, inlet diameter, outlet diameter, throat diameters of two‐connected CD fractures, fracture wall curvature, roughness amplitude, and frequency. As a result, the throat diameter crucially affected choked flow occurrence and maximum Ma. When the inlet and outlet diameters varied, the profiles for Ma variation were consistent in the converging and diverging segments, respectively. In addition, regardless of change in the throat length, the position of maximum Ma was nearly constant with showing the position length ratio of 0.13–0.14. However, roughness of fracture wall significantly influenced the Ma variation and occurrence of shock. In particular, backflows segregated from the main CO2 flow were observed near the wall roughness. Plain Language Summary: Choked flow is a fluid‐mechanical process that restricts the mass flow rate of fluid and it can be occurred when fluid velocity overcomes its sound speed. When CO2 is injected into the targeted geologic formation, choked flow can occur due to highly pressurized flow within the fractures located near the CO2 injection well. Once choked flow occurred, the shock, which accompanies substantial changes in the thermodynamic properties of CO2, follows in the fractures. In the study, choked flow is generated within the converging‐diverging (CD) fracture which serves as a pathway of injected CO2, and its cross‐sectional area decreases and increases again after the "throat." We assumed that the CD fractures have various morphologic properties and analyzed the relationship between the fracture morphology and shock properties. The results highlighted that the throat diameter and fracture roughness mainly affected choked flow occurrence and shock properties. Findings here are applicable to other site‐specific studies, such as volcanoes, geysers, geothermal fields, and underground hydrogen storage sites where highly compressed fluid often migrates through subsurface fractures or any types of geologic conduits. Key Points: CO2 flow within the fracture was simulated to evaluate the effect of fracture morphology on choked flow and shock generationMorphologic properties including throat diameter and length, inlet and outlet diameter, number of throats, and wall roughness were variedThroat diameter influenced the Mach number (Ma); a complicated trend of Ma and backflow were observed owing to wall roughness [ABSTRACT FROM AUTHOR]