CO₂ injection into porous sandstone reservoirs offers a promising pathway to curb anthropogenic carbon emissions, but poses risks of leakage and induced seismicity from stress perturbations and fault reactivation without meticulous monitoring. Here, we present a time-lapse monitoring approach based on laboratory measurements of ultrasonic Vp, Vs and corresponding peak amplitudes in critically stressed, partially saturated North Sea sandstones (porosity 9–23%). Our experiments show that Vp and Vs exhibit higher sensitivity (4–15%) to stress changes compared to fluid saturation changes (0.8–1%), whereas amplitudes are more responsive (30–500%) to saturation, showing staggered change when brine is displaced by CO₂. Under pure stress perturbation, amplitude variations are smaller (10–50%). During elastic deformation, the Vp/Vs ratio decreases while the ratio of their corresponding amplitudes increases, underscoring the need for both P- and S-wave measurements. Velocity and amplitude changes are more pronounced in high-porosity rocks. In a critically stressed state (beyond yield/before failure), the rise in pore fluid density from CO₂ injection boosts shear wave amplitudes, offsetting attenuation from inelastic deformation. Knowing the pre-injection stress state enables these velocity and amplitude trends to serve as robust indicators of reservoir conditions during and after CO₂ injection. This cost-effective approach can be adapted to reservoir-scale monitoring and extends beyond CCS, supporting enhanced detection of stress and fluid-induced changes in subsurface formations.

Micro-structural attributes of Chumathang granite from Leh, India, were experimentally determined in the temperature range from 25 to 600 °C for enhanced geothermal systems (EGS). P-wave velocity, thermal crack generation, and pore attributes were analyzed using a combination of pulse ultrasonic velocity study, 3D X-ray tomography and low-pressure gas adsorption experiments, respectively. Results indicate that thermal crack development is driven by mineral composition and differential thermal expansion, with a significant increase in the thermal damage factor between 450 ∘C and 600 ∘C, accompanied by visible cracks at 600 ∘C. Surface area and pore volume decreased up to 300 ∘C due to mineral dissolution, then slightly increased up to 600 ∘C due to microfracture formation. Pore size distribution showed a dominance of coarser mesopores, and fractal dimensions decreased with temperature, reflecting simpler pore geometries. These findings enhance the understanding of granite’s microstructural changes under thermal stress, informing the optimization of EGS heat extraction efficiency.

The global expansion of subsurface CO₂ and hydrogen storage, alongside geothermal energy development, offers promising pathways for gigaton-scale CO₂ abatement. However, fluid injections and associated thermal effects can significantly alter reservoir stress states, risking fault reactivation and compromising caprock integrity. Direct stress measurements in the subsurface remain technically challenging, particularly beyond the near-wellbore zone. This study investigates how stress-induced changes in ultrasonic P- and S-wave velocities and amplitudes can serve as early indicators of irreversible rock deformation. Using triaxial cyclic and failure experiments on core samples from offshore Netherlands (depths: 3.1–4.2 km; porosity: 8–23 %), we demonstrate that wave velocities and amplitudes increase with axial loading in the elastic regime but decline progressively following crack initiation—well before mechanical failure. This trend reversal provides a reliable sonic precursor to failure. We propose a field-applicable traffic-light monitoring framework using sonic parameters to infer stress changes during injection operations. The observed inverse relationships between porosity and both mechanical strength and sonic velocity, along with the porosity-dependent velocity enhancement under confinement, present a novel opportunity to develop constitutive geomechanical models directly from reservoir sonic logs. This work advances non-invasive stress monitoring approaches and provides engineering geologists with robust tools to improve safety and predictability in subsurface energy storage projects. Moreover, such techniques can also be translated to integrity monitoring for underground mines and engineered structures.

A central goal of laboratory seismology is to infer large-scale seismic processes from small-scale experiments, with acoustic emissions (AE) being a common observable. These signals, indicative of microfracturing, slip localization, and damage evolution, are often paralleled with earthquakes to understand seismic behaviors. This study challenges traditional perspectives by applying Coulomb rate-and-state seismicity theory, originally developed for earthquake clustering, to AE experiments. This theory maps stressing history to seismicity rates using rate-and-state friction, however, its validity under controlled experimental conditions remains an open question. We conducted four experiments on a sawcut sample of red felser sandstone, representing a fault under variable stress conditions. Adjustments in loading rates and initial conditions revealed that, while a single free parameter A—related to the direct effect—should suffice, a rescaling of the model by 1.5 to 2.2 was necessary for fitting the data. Differences in values across experiments appeared mostly non-systematic, and partial data usage did not yield consistently systematic parameter migrations. These findings suggest that fault microstructure may complexly alter parameter values during loading beyond what is accounted for in the Coulomb rate-and-state theory. Nonetheless, with the introduction of the scaling parameter, the Coulomb rate-and-state theory effectively captures the fundamental aspects of AE responses to complex controlled loading histories.

Lithologically diverse shales were collected from two different proliferous basins, namely, the Korba (SM) and Raniganj Basin (BK) in India, and were experimented with at an isothermal condition using CO₂ and N₂ as probe gases in the low-pressure gas adsorption method, demonstrating the disparity between shale pore attributes and surface roughness. The Korba Basin is one of the potential sites for gas storage and production in India and needs to be explored in terms of pore statistics. Literature reviews demonstrate that pore characteristics in shale changes with depth, organic matter, and mineral composition, which can elucidate the gas storage potential for anthropogenic CO₂ storage. Gas adsorption capacity and surface roughness are directly associated with the difference in organic and mineral compositions, which certainly affects the phase distribution of flow regimes in shale reservoirs. The result determines that micropore and mesopore attributes are in good correlation with the TOC and clay minerals, respectively. SM shale shows 30-37% higher micropore attributes and 17-19% lower mesopore attributes than those of BK shales. Furthermore, the siderite content shows a variance in the pore size distribution in BK shales. The fractal dimension (D_s) is evaluated based on the N₂ adsorption isotherm curve using the Frenkel-Halsey-Hill model. SM shales show a strong correlation with both micropores and mesopores at low relative pressure regimes, while BK shales depict their dominance with mesopores at the high relative pressure regime. Therefore, this research provides a preliminary attempt to determine the influence of changes in the depth, surface roughness, and organic and mineral compositions on shales. However, a complete extrapolation of other reservoir factors, viz., seam thickness, shale-water interaction, and permeability variation at reservoir conditions, is vital to unlocking the technical and environmental feasibility of CO₂ storage and gas production in these basins.

Extracting gas from unconventional shale reservoirs with low permeability is challenging. To overcome this, hydraulic fracturing (HF) is employed. Despite enhancing shale gas production, HF has drawbacks like groundwater pollution and induced earthquakes. Such issues highlight the need for ongoing exploration of novel shale gas extraction methods such as in situ heating through combustion or pyrolysis to mitigate operational and environmental concerns. In this study, thermally immature shales of contrasting organic richness from Rajmahal Basin of India were heated to different temperatures (pyrolysis at 350, 500 and 650 °C) to assess the temperature protocols necessary for hydrocarbon liberation and investigate the evolution of pore structural facets with implications for CO₂ sequestration in underground thermally treated shale horizons. Our results from low-pressure N₂ adsorption reveal reduced adsorption capacity in the shale splits treated at 350 and 500 ºC, which can be attributed to structural reworking of the organic matter within the samples leading to formation of complex pore structures that limits the access of nitrogen at low experimental temperatures. Consequently, for both the studied samples BET SSA decreased by ∼58% and 72% at 350 °C, and ∼67% and 68% at 500 °C, whereas average pore diameter increased by ∼45% and 91% at 350 °C, and ∼100% and 94% at 500 °C compared to their untreated counterparts. CO₂ adsorption results, unlike N₂, revealed a pronounced rise in micropore properties (surface area and volume) at 500 and 650 ºC (∼30%–35% and ∼41%–63%, respectively for both samples), contradicting the N₂ adsorption outcomes. Scanning electron microscope (SEM) images complemented the findings, showing pore structures evolving from microcracks to collapsed pores with increasing thermal treatment. Analysis of the SEM images of both samples revealed a notable increase in average pore width (short axis): by ∼4 and 10 times at 350 °C, ∼5 and 12 times at 500 °C, and ∼10 and 28 times at 650 °C compared to the untreated samples. Rock-Eval analysis demonstrated the liberation of almost all pyrolyzable kerogen components in the shales heated to 650 °C. Additionally, the maximum micropore capacity, identified from CO₂ gas adsorption analysis, indicated 650 °C as the ideal temperature for in situ conversion and CO₂ sequestration. Nevertheless, project viability hinges on assessing other relevant aspects of shale gas development such as geomechanical stability and supercritical CO₂ interactions in addition to thermal treatment.

Organic-rich shales are marked by the presence of complex pore structures and extremely low permeabilities, which present challenges while extracting hydrocarbon from them. With the potential negative environmental impacts of hydraulic fracturing, recent research has focused on alternative techniques such as in situ combustion/pyrolysis for enhancing the permeability of shales. In this study, low-temperature combustion was used to evaluate the evolution of pore structures in shales for contrasting thermal maturities and organic matter type from the Raniganj and Bikaner-Nagaur basins of India. The heating temperatures were decided on the basis of the combustion behavior of the samples observed from thermogravimetric analysis (TGA). Results from low-pressure N₂ and CO₂ gas adsorption indicate that mesopore and micropore structures in shales are significantly altered due to thermal treatment at higher temperatures. In general, for both of the shales, initially, when treated at lower temperatures, with respect to the raw shales, the mesopore surface area and fractal dimensions were observed to increase with lowering of pore sizes and vice versa. Similar to the mesopore trend, the increase-decrease trend of microporosity with heating was observed to be consistent for both of the shales. The oil-window mature shales showed a significant increase in micropores compared to the thermally immature shales. Microstructural investigations using high-resolution imaging also indicated a dramatic alteration of visible porosity with thermal treatment.

Pore orientation in shale governs the fluid transport properties that are key to hydrocarbon production and potential CO₂ sequestration. The present work deals with the detailed study of nano-heterogeneities in shales, across the bedding plane, of varying thermal maturity and total organic carbon content using scanning small-angle X-ray scattering (SAXS) experiments. The complementary X-ray Micro-Computed Tomography (μCT) and functional group mapping elucidate the heterogeneity in micrometer resolution. 2D SAXS profiles of the shales show elliptical patterns indicating the nanoscale pore anisotropy in shale. The orientation of pores and their spatial variation is strongly dependent on the content of organic matter. The variance in the anisotropy parameter is validated with chemical mapping and high-resolution 3D imaging.

Pore characterization helps to estimate the coalbed methane recovery and carbon storage potential of the reservoir. Earlier research on the characteristics of coal pores has shown that coal has high hydrocarbon storage potential in the adsorbed state, but few studies have shown the influence of chemical heterogeneities and depth on the adsorption potential of the coal. With the objective of studying the effect of chemical variation, depth, and surface roughness on gas adsorption potential, this study combines coal composition analysis and adsorption-based pore characterization of coal and shale samples coupled with high-resolution imaging and X-ray scattering measurements. Variation in pore features is correlated with varying depth and composition. A decrease in the mesopore volume and surface area is observed with an increase in the depth and total organic content and inverse behavior is observed for micropores. Scanning electron microscopy images depict the change in the pore shape from semi-spherical OM pores to elongated pores with depth, and samples with high mineral content show a dominance of inter- and intraparticle pores. Fractal dimension values estimated from SAXS are notably higher than N₂-LPGA-derived values (i.e.,─D_S > D_N) due to the incorporation of inaccessible pores, which reflects an increase of up to 62% in SAXS estimated mesopore volume and surface area. This study will provide a better approach to understand the impact of composition, depth, and surface roughness over the gas storage potential in coal reservoirs.

A combination of high-resolution imaging, low-pressure gas adsorption, and small-angle X-ray and neutron scattering quantifies changes in the pore characteristics of pulverized shale samples under oxic and anoxic environments up to 300 ℃. Clay-rich early-mature shales have a fair potential to generate hydrocarbons, the total organic carbon content of which lies within a range of 2.9 % to 7.4 %. High-resolution imaging indicates restructuring and coalescence of Type III kerogen-hosted pores due to oxic heating, which causes up to 580 % and 300 % increase in the surface area and pore volume of mesopores respectively. Similarly, up to 300 % and 1200 % increase in micropore surface area and pore volume is observed post oxic heating. However, during anoxic heating, bitumen mobilizes, leads to pore-blockage, and reduces the surface area and pore volume up to 45 % and 12 % respectively without any significant mass loss up to 350 °C. Between 400 and 550 °C, considerable loss in mass occurred due to breaking of organic matter, facilitated by the presence of siderite that caused up to 30 % loss in mass. The test conditions display starkly opposite effects in pores that have a width of < 100 nm when compared to the larger macropore domain, which has a pore width in the range of 100 to 700 nm as inferred from their small-angle X-ray (SAXS) and neutron (SANS) scattering behaviour, respectively. Despite the formation of new mesopores or the creation of new networks of pores with rougher surfaces, the fractal behavior of accessible mesopores in combusted shales minimally increase mesopore surface roughness. The pyrolyzed shales exhibit decreased mesopore surface roughness at higher temperatures, which indicates smoothening of pores due to pore blocking. Increase in pore volume and surface area due to oxic-heat treatment enhances the feasibility of long-term CO₂ storage in shales.

Hydrogen is a promising energy carrier for a low-carbon future energy system, as it can be stored on a megaton scale (equivalent to TWh of energy) in subsurface reservoirs. However, safe and efficient underground hydrogen storage requires a thorough understanding of the geomechanics of the host rock under fluid pressure fluctuations. In this context, we summarize the current state of knowledge regarding geomechanics relevant to carbon dioxide and natural gas storage in salt caverns and depleted reservoirs. We further elaborate on how this knowledge can be applied to underground hydrogen storage. The primary focus lies on the mechanical response of rocks under cyclic hydrogen injection and production, fault reactivation, the impact of hydrogen on rock properties, and other associated risks and challenges. In addition, we discuss wellbore integrity from the perspective of underground hydrogen storage. The paper provides insights into the history of energy storage, laboratory scale experiments, and analytical and simulation studies at the field scale. We also emphasize the current knowledge gaps and the necessity to enhance our understanding of the geomechanical aspects of hydrogen storage. This involves developing predictive models coupled with laboratory scale and field-scale testing, along with benchmarking methodologies.

At COP26, India announced strong climate commitments of reaching net-zero greenhouse gas emissions by 2070. Meeting this target would likely require substantial deployment of CO ₂ capture and storage (CCS) to decarbonize existing large-point sources of CO ₂. This study attempts to evaluate opportunities for deployment of CCS in India in the forthcoming decades. A geographic information system-based approach was adopted for mapping existing sources of CO ₂ with the sinks. The results show that regionally-appropriate ways of moving towards CCS at scale exist in both the power and industrial sectors. Coupled analysis of these sectors with sinks shows that eight clusters may be developed throughout the country to sequester 403 Mt-CO ₂ annually. These clusters are concentrated near Category-I oil basins and the Category-I coalfields (Damodar Valley), which may also create suitable financial incentives by incremental oil and coalbed methane recovery, respectively. Furthermore, a first-order costing analysis evaluates that the cost of avoidance across basins may range from –$31 to $107/t-CO ₂, depending on the type of storage reservoir and the proximity to large-point sources. A total of 12 suitable hubs and clusters were created based on annual emissions above 1 Mt-CO ₂ of each large-point source and their proximity with geological sinks.

Hydraulic fracturing has transformed the international energy landscape by becoming the go-to method for the exploitation of natural gas from unconventional shale reservoirs. However, in the recent years, the search for an alternative method of shale-gas exploration has intensified, because of various problems (e.g., contamination of ground and surface water, overexploitation of precious water resources, air pollution, etc.) associated with the usage of water-based fracturing techniques. The use of CO2 for shale gas exploitation has emerged as a better alternative to aqueous-based gas exploration techniques. CO2 when injected into deep shale reservoirs, transitions into supercritical CO2 (SC-CO2) when temperature and pressure condition exceeds the critical point, i.e., 31.1 °C and 7.38 MPa. In this paper, we comprehensively review the impact of SC-CO2 on shale gas reservoirs during the different stages of shale-gas exploration, i.e., (i) drilling, which involves the superiority of SC-CO2 over water-based drilling fluids, in terms of achieving under-balanced well condition, higher rates of penetration, and resistance to formation damage; (ii) fracturing, which involves factors affecting the tortuosity of fractures created by SC-CO2 fracturing, breakdown pressure, and proppant-carrying capacity; and (iii) injection, which involves the twin-headed benefit of enhanced recovery due to CO2/CH4 competitive adsorption and geological sequestration, CO2 vs CH4 excess sorption as a function of pressure, etc. Several research works have indicated discrepancies on how SC-CO2 impacts different shale properties. Some studies show low-pressure N2-gas-adsorption-derived surface area and total pore volume to be increasing with SC-CO2 imbibition, while others show a decreasing trend for the same. Similarly, for some shales, the quartz content, along with the clay mineral contents, decreased as the exposure to SC-CO2 increased, while in some other studies, with similar long-term exposure to SC-CO2, the quartz content was observed to increase along with the decrease in clay content and vice versa. Essentially, the increased exposure to SC-CO2 results in the dissolution of primary porous structures and fractures, and reformation of newer porous structure and conduits in shales. Nonetheless, these changes in the mineralogy weaken the microstructure of the rock bringing significant changes in the mechanical properties of the shales with implications on the wellbore stability and fracturing efficiency. The mechanical properties such as uniaxial compressive strength (UCS), Young's modulus, and tensile strength decrease as the SC-CO2 saturation period increases. However, some studies have shown factors like bedding angle and phase-state of CO2 having varying effect on the strength behavior of the shales. Moreover, changes in the structure of shales caused by the creation of fractures and the reduction of their strength can also pose major risks, because of potential leakage of CO2 through these created pathways. How these processes would interact at field scale would control the sealing capacity, especially at field-scale for addressing long-term seepage of CO2.