ABSTRACT In Bommer et al. (2024), we presented a critical review of the process through which the current logic tree for the maximum magnitude used in seismic hazard and risk calculations for induced earthquakes in Groningen was obtained. The article intended to initiate a discussion for which our premise is that the current maximum magnitude distribution may be excessively conservative, impacting both the quantitative risk assessment and the public and regulatory perception of risk. In his Comment, Vlek (2024b) misrepresents our article and makes inferences that have no basis in our article. He also puts forward numerous ideas, many of which have no connection to our article and others of which seem to reflect statements that we make, despite having recently published a discursive article on this very topic. There are several serious technical weaknesses in the comment, which we explain in this reply to minimize the confusion that the comment could create.

Gas production in the Groningen field in the northern Netherlands began in 1963. Since 1991, many production-induced earthquakes have occurred—the largest reaching magnitude M 3.5 in 2012. In October 2023, the Dutch government closed the field—a decision that was justified by the potential threat of larger earthquakes occurring with continued gas extraction. This outcome highlights how the estimation of maximum magnitude for induced earthquakes can have important implications for risk perception by regulators and the public. Thus, the estimation of maximum magnitude for induced earthquakes that are not physically realizable can lead to unwarranted conservatism. Over almost three decades, considerable effort has been invested by several researchers to estimate the maximum magnitude of induced earthquakes in Groningen. These efforts culminated in international workshops focusing exclusively on this question in 2016 and 2022. The purpose of these workshops was to inform the decision-making of an expert panel charged with formulating a logic tree for the maximum magnitude of Groningen earthquakes. We argue that the evaluation of the final distribution of maximum magnitudes is overly conservative in terms of the largest events induced in the reservoir and, most importantly, the likelihood of triggering even larger tectonic earthquakes outside the gas-producing reservoir. Given the serious and far-reaching consequences of maximum magnitude estimates, we reconsider the approach of these assessments to draw lessons that may be critical for future energy-related projects associated with induced seismicity.

Fuel cell electric vehicles utilizing hydrogen are one option for reducing emissions in the transportation sector. Future hydrogen demand for the mobility markets will be partially dependent on the evolution of state and national policies and incentives. Hydrogen from natural gas plus carbon capture and sequestration (SMR-CCS) is one pathway for manufacturing hydrogen without significant carbon dioxide (CO2) emissions. This paper describes a methodology for assessing hydrogen market demand, CO2 storage options, community impacts (air quality and community vulnerability/environmental justice concerns), land ownership and technoeconomics for the mobility market in northern California, but has application globally. Our analysis indicates that a single facility with 250 t/day hydrogen generation capacity would provide enough hydrogen to supply the Bay Area and Sacramento regions of California in a mid-case demand scenario. With existing federal and state incentives, we estimate the levelized cost of hydrogen from natural gas plus carbon capture and sequestration to be $0.13 per kg (highly dependent on California Low Carbon Fuel Standard credit assumed to be $100/ton CO2), which is competitive with grey hydrogen that averages $0.65 /kg in California. In addition, based on subsurface criteria, community impact analysis, and land ownership status, 7 sites in northern California appear to be feasible prospects for a collocated SMR-CCS new build facility. The primary barrier to CCS projects in California continues to be the regulatory framework. Further work with key stakeholders, including state and federal legislators, is needed to enhance the commercial attributes of CCS projects and public acceptance of such projects.

Summary Large scale CO2 storage in the subsurface poses significant geomechanical challenges that include the potential for inducing seismicity and porosity and permeability changes in depleted resesrvoirs.

Carbon capture and storage (CCS) is an essential greenhouse gas mitigation strategy. Consolidating CO2 sources and sinks can enable the widespread adoption of CCS, and the success of hub-scale projects depends on finding an appropriate sequestration complex. This work developed a criteria-driven framework to assess the potential suitability of saline formations for carbon storage. The workflow uses a three-stage process that screens, ranks, and characterizes potential saline storage formations based on three categories: (1) capacity and injectivity optimization, (2) retention and geomechanical risk minimization, and (3) siting and economic constraints. In this framework, data confidence has been incorporated into site ranking, which provides the user with information about the degree of uncertainty associated with the evaluation. The methodology can be applied to sites in various geological and geographical environments and incorporates general and project-specific criteria. This quantitative, criteria-driven approach was applied to two areas of interest in the Gulf of Mexico, and one site was identified for further assessment. In addition, this workflow was applied to four existing CCS projects— Sleipner, IBDP, In Salah, and Snøhvit—to see how they would have scored and ranked pre-development.

We apply binary logistic regression to correlate fracture shear-slip criticality to hydraulic conductivity using data from four deep scientific boreholes in fractured crystalline rocks. In each borehole, an optimized decision boundary is obtained by maximizing the joint probability of classifying all fractures in consideration as critical or not. All four cases feature an optimized decision boundary close to the empirical rock friction (mu = 0.6), corroborating the applicability of laboratory-derived friction coefficients to faults in situ. Utilizing this statistical technique, we demonstrate that one can determine the in situ stress orientation and relative magnitude based only on whether fractures of varied orientations are hydraulically conductive, or not. The stress inversion results are consistent with independent stress measurements in each of the four case studies.

We report a study using teleseismic P-wave receiver functions to infer the orientation of the maximum horizontal principal stress from the direction of upper crustal shear-wave velocity anisotropy. We apply an inverse approach using the Neighborhood Algorithm to conduct a nonlinear search, attaining a best-fitting crustal model that includes shear velocity anisotropy. Unlike previous methods reported in the literature, this method is able to distinguish anisotropy in the upper, brittle crust from that in the lower, ductile crust in certain instances. We apply this method to teleseismically recorded earthquakes in the Central Valley of California, the Permian Basin, Texas, northern Oklahoma and sites near the San Andreas Fault in California. Of the forty-one stations to which we apply this method, twenty have a good apparent signal. A misfit calculation is performed by calculating a zero-lag cross-correlation coefficient for each modeled receiver function with the data for a given back azimuth range. While the fast polarization direction in the upper crust of some of these stations aligns with independent indicators of the direction of the maximum horizontal principal stress, the fast direction in the upper crust at other stations does not, apparently indicating that the anisotropy was resulting from a different mechanism.

There is a pressing need to rapidly, and massively, scale up negative carbon strategies such as carbon capture and storage (CCS). At the same time, large-scale CCS can enable ramp-up of large-scale hydrogen production, a key component of decarbonized energy systems. We argue here that the safest, and most practical strategy for dramatically increasing CO 2 storage in the subsurface is to focus on regions where there are multiple partially depleted oil and gas reservoirs. Many of these reservoirs have adequate storage capacity, are geologically and hydrodynamically well understood and are less prone to injection-induced seismicity than saline aquifers. Once a CO 2 storage facility is up and running, it can be used to store CO 2 from multiple sources. Integration of CCS with hydrogen production appears to be an economically viable strategy for dramatically reducing greenhouse gas emissions over the next decade, particularly in oil- and gas-producing countries where there are numerous depleted reservoirs that are potentially suitable for large-scale carbon storage.

Limited understanding of state of stress has led to wellbore complications attributing to significant nonproductive time during drilling operations in the Barmer Basin, northwestern India. This paper deals with determination of state of stress in the hydrocarbon-bearing Barmer Basin by incorporating well data, earthquake aftershock data, and structural fieldwork data. Vertical stress (S-v), pore pressure (P-p), and minimum horizontal stress (S-hmin) were estimated from petrophysical logs using the effective stress approach and are calibrated to available pressure and stress measurements. Maximum horizontal stress (S-Hmax) is constrained using frictional faulting theory. A new estimation approach, independent of S-hmin, is presented in the zones where wellbore failures such as borehole breakouts (BOs) and drilling induced tensile fractures (DITFs) occur together. Stress orientation was inferred from wellbore failures (BOs and DITFs) recorded by image logs, shear sense from deformation bands, and stress inversion from aftershock data. The S,, ranges from 0.9 to 1.05 psi/ft, Pp ranges from hydrostatic to 0.65 psi/ft, Shmin ranges from 0.7 to 0.98 psi/ft, and SHmax constrained by the presence of BOs and DITFs ranges from 1.2 to 1.82 psi/ft and 1.24 to 1.85 psi/ft, respectively. The SHmax from the new combined failure approach ranges from 1.09 to 1.82 psi/ft. The SHmax orientation is predominantly north-south and is consistent spatially basin-wide. Finally, the relative comparison of the three principal stresses suggests a strike-slip (S-Hmax > S-v > S-hmin) stress state in the basin and marginally reverse (S-Hmax > S-hmin >= S-v) in the northern part, where transpressional features are evident. The observed present-day strike-slip stress state and principal stress (S-Hmax) orientation is consistent with the stress inversion analysis of Bhuj earthquake aftershock data. Also, based on paleostress analysis of outcropping structural fabrics and kinematic indicators, and understanding of the Indian plate movement and collision tectonics in the Himalayas during the Cenozoic, it is inferred that the area has been under a strike-slip stress state since at least the Oligocene.

ABSTRACT: The impacts of supercritical carbon dioxide (scCO2) on fracture permeability and fracture surface characteristics of shale samples with various mineral compositions were studied in this paper. We measured permeability and fracture normal displacement (FND) at different confining pressures and pore pressures using both argon gas and scCO2. Our results indicate that mechanical compaction and fine particles migration have opposite impacts on permeability and FND, especially in clay-rich shales. It appears that fine particle migration creates a self-propping aperture that results a permeability increase in the subsequent cycle. However, inelastic compaction associated with loading/unloading cycles reduce the permeability. In addition, an increase in permeability (and associated fracture surface degradation) were observed after more than 3 days of exposure to scCO2 due to carbonate dissolution. The rates of permeability increase in saw cut fractures are larger than FND suggesting that new flow pathways were created because of carbonate dissolution and that controls the transport characteristics of the scCO2-interacted fracture surface. 1. INTRODUCTION Geological carbon capture and storage (CCS) is one of the techniques to reduce green gas emissions and storage of CO2 in unconventional reservoirs has been the focus of many studies in the last few years (Goodman et al. 2020; Kim et al. 2017; Kolawole et al. 2020). Methane is found as a free phase in pores and fractures and also as adsorbed gas on clay or organic matter in shale gas plays. After the reservoir is depleted, CO2 could be sequestrated by similar mechanisms as methane in two populations. Supercritical CO2 (scCO2) has been also proposed as an alternative fracturing fluid for hydraulic fracturing operations in unconventional reservoirs (Ishida et al. 2012; Jia et al. 2019; Zhang et al. 2017). The phase diagram for carbon dioxide shows that CO2 behaves as a supercritical fluid that adopts properties somewhere between a gas and a liquid above the critical temperature and critical pressure of 31.1 °C and 7.37 MPa, respectively. Compared to aqueous-based fluids, scCO2 can develop more complicated fracture networks, improve shale gas recovery by preferential adsorption behaviors of CO2 over methane, reduce flow blockages and reduce water consumption (Zhou et al. 2020). For instance, a study on Yan-2011 shale gas by Li and Kang, (2018) showed that after scCO2 fracturing, the CO2-retention rate was 39.5% and the shale gas production rate was increased 1.5 times. Nevertheless, scCO2 has a lower viscosity than water in the reservoir temperature and pressure and that reduces its efficiency of carrying proppants into the fracture networks.

Knowledge of layer-to-layer variations of the least principal stress, S hmin, with depth is essential for optimization of multi-stage hydraulic fracturing in unconventional reservoirs. Utilizing a geomechanical model based on viscoelastic stress relaxation in relatively clay rich rocks, we present a new method for predicting continuous S hmin variations with depth. The method utilizes geophysical log data and S hmin measurements from routine diagnostic fracture injection tests (DFITs) at several depths for calibration. We consider a case study in the Wolfcamp formation in the Midland Basin, where both geophysical logs and values of S hmin from DFITs are available. We compute a continuous stress profile as a function of the well logs that fits all of the DFITs well. We utilized several machine learning technologies, such as bootstrap aggregation (or bagging), to improve the generalization of the model and demonstrate that the excellent fit between predicted and observed stress values is not the result of over-fitting the calibration points. The model is then validated by accurately predicting hold-out stress measurements from four wells within the study area and, without recalibration, accurately predicting stress as a function of depth in an offset pad about 6 miles away.

We conducted a suite of experiments to evaluate the long-term permeability evolution of shale rocks under constant effective stress, before, during, and after interaction with supercritical carbon dioxide (scCO2). To do so, we measured the time-dependent evolution of argon permeabilities for the pre- and post-reacted samples (i.e., before and after long-term interaction with scCO2). In addition, we obtained permeability evolution during long-term interaction with scCO2. The samples showed either relatively constant permeabilities or a moderate decrease during pre-reaction long-term argon tests. The permeability evolution during long-term CO2 tests showed continuous increase, continuous decrease, or cycles of increase/decrease in permeability. The long-term response of the samples to CO2 included phenomena such as (i) salt precipitation, (ii) swelling-induced cracks, and (iii) carbonate dissolution. While it is obvious that salt precipitation and swelling-induced cracks decrease and increase the permeability, respectively, the sample response to carbonate dissolution proved to be more complex and may increase or decrease the permeability. The permeability evolution during post-reaction long-term argon injection is also affected by the contribution of each of these three phenomena, during long-term interaction with CO2. We observe increase, decrease, and constant permeability evolution during post-reaction argon tests. Our experiments reveal that the initial permeability of the samples plays a significant role on the long-term permeability response of shales in the presence argon and scCO2 fluids. This study shows that when shales are hydraulically fractured with CO2 their initial permeability has a more significant role than their permeability evolution over time.

Carbon capture and sequestration (CCS) is playing a role in mitigating carbon emissions and that role is expected to grow dramatically with time. Clustering CO2 sources and sinks through hubs is one way to achieve large-scale deployment of CCS and widespread decarbonization of the energy sector. A key element to the success of hub projects is finding a suitable sequestration site to store these combined emissions. In this study, a quantitative, criteria-driven methodology was developed to assess the potential suitability of depleted oil and gas reservoirs for carbon storage. The methodology utilizes a three-stage process that screens, ranks, and characterizes potential sites based on three categories: (1) capacity and injectivity optimization, (2) retention and geomechanical risk minimization, and (3) siting and economic constraints. Many potential sites are assessable using this methodology until an optimal depleted reservoir, or geographically adjacent set of reservoirs, is identified. The framework is designed to provide insights into the suitability of depleted reservoirs in a variety of different geological environments as well as to be adaptable to a project's specifications. Specifically, the criteria-driven workflow was applied to fields in the Gulf of Mexico and screened 1,317 fields to identify 10 clusters of 31 fields for further assessment and then ranked those fields and clusters to identify the most suitable sites for secure storage.

The Longmaxi shale is an extensive, prolific unconventional play in southwestern China. Its development in the Changning area is affected by ineffective hydraulic fracturing (HF) stimulation, fault reactivation and casing damage. It is suspected that the stress contrast within and between the shale reservoirs and the formations above and below matters to hydraulic fracture propagation and reservoir stimulation. To this end, the Longmaxi shale in the Changning area deserves a dedicated quantification of the in situ stress state and its variations. In this study, we re-visit the available data from one of the play’s first appraisal wellbores (X01) for an integrated geomechanics study, focusing on profiling the stress across the Longmaxi and its adjacent formations. Combining geophysical logs and other stress indicators, we re-interpret its stress profile in the context of lithological variations. The resulting stress variations are modeled primarily through a viscoplastic stress relaxation framework, compared with the results via the frictional equilibrium and an elastic theory (the Extended Eaton model). We offer some discussions on the differences and similarities of these stress profiling methods, and examine their applicability to Longmaxi shale in the Changning area. Our objective is to connect the lithology-controlled stress variations to the first-order complexities (HF ineffectiveness and fault reactivation) that have been observed in the area to date.

In this paper, we present comprehensive data on stress orientation and relative magnitude in areas throughout North America where unconventional oil and gas are currently being developed. We find excellent agreement between maximum horizontal principal stress (S-Hmax) orientations over a wide range of depths, using multiple methods. In all basins studied, we observed coherent stress fields that in some cases vary systematically from one part of a basin to another. In the Appalachian Basin in the eastern United States, S-Hmax is oriented northeast-southwest to east-northeast- west-southwest and the style of faulting is compressive, transitioning from reverse faulting in eastern Pennsylvania and New York to principally strike-slip faulting in western Pennsylvania, Ohio, and West Virginia. In the midcontinent, central Oklahoma is characterized by an approximately east-west S-Hmax direction and strike-slip faulting. The Fort Worth Basin in northeastern Texas is characterized by normal-strike-slip faulting and a north-northeast-south-southwest S-Hmax direction. In the Midland subbasin of western Texas, S-Hmax is consistently approximately east-west and normal-strike-slip faulting is observed. Farther west, the Delaware subbasin of western Texas and southeastern New Mexico is characterized by normal faulting and S-Hmax rotates similar to 150 degrees clockwise from north to south. Marked changes in S-Hmax, direction also occur across the Raton Basin of southern Colorado and northern New Mexico, the Denver-Julesburg Basin in northern Colorado, and the Uinta Basin in northeastern Utah, likely associated with their location near the margins of extensional provinces. The new data sets we present help improve operational efficiency by constraining absolute stress magnitudes and the ideal azimuth to drill horizontal wells (i.e., perpendicular to the local S-Hmax orientation) and make it possible to predict which fractures and faults are likely to be activated during hydraulic stimulation.

ABSTRACT: We used core samples from the Wolfcamp formation in the Permian Basin to conduct creep experiments with argon and scCO2 as the pore fluids. We conducted the tests at a temperature of ~ 42 °C, confining pressures of 40 and 70 MPa, pore pressures of 10 MPa, and various levels of differential stress. Creep stages lasted for either 24 or 48 hours and prior to creep the Young’s modulus was estimated based on the loading history. When CO2 results are compared to the argon results, the Young’s modulus of the carbonate-rich sample increases, while the Young’s modulus of the clay-rich sample decreases. The viscoplastic response with scCO2 as the pore fluid generally indicates more significant deformation. This is attributed to the aggregate effects of carbonate dissolution and swelling strain of clays and kerogen. A power-law model has been implemented to predict the longer-term creep response of the samples. The fitting parameters are satisfactory; however, additional investigation is needed for the scCO2 case, due to time-dependent chemical interactions with the sample. 1. INTRODUCTION Geological storage of carbon dioxide (GCS) is one of the relatively short-term feasible solutions to climate change (Bouckaert et al., 2021). While the storage of CO2 is likely to occur in a porous sandstone reservoir, the target formation needs to be sealed by a low permeability caprock such as shale. Employing CO2 as the stimulation fluid of unconventional reservoirs is another method of sequestering carbon dioxide into the subsurface. In both applications, the shale formation is exposed to CO2 over prolonged periods of time. Therefore, it is necessary to investigate the alterations in the mechanical/transport characteristics of shale reservoirs when they are exposed/interacted to/with CO2. Shales typically possess ultra-low permeabilities (usually below 1 μD) with very complex micro-structure, and is mainly composed of quartz, carbonates, clays, and organic matter (Zoback and Kohli, 2019). Interaction between shales and carbon dioxide in the presence of in-situ water results in (i) adsorption-induced swelling of clays and organic matter, (ii) dissolution of carbonate minerals due to interaction with carbonic acid, and (iii) mineral/salt precipitation (Linder et al., 2016; Kamali-Asl et al., 2021). Some past research has been dedicated to the changes in the micro-structure of shales as they are exposed to dry CO2 or CO2-saturated brine (Sanguinito et al., 2018; Hadian and Rezaee, 2020), while others have focused on changes of porosity/permeability (Wu et al., 2017; van Noort and Yarushina, 2019).

While there is continuing interest in geologic CO2 storage, experimental studies on poroelastic characteristics of reservoir rocks during depletion and subsequent CO2 injection are scarce. Rock stiffness, confining stress, and pore pressure control the poroelastic response of saturated rocks. Also, the stress and pore pressure evolution during injection is a key parameter to understanding operations thresholds for CO2 storage projects. As depleted fields in the Gulf of Mexico have been identified as strong candidates for CO2 storage projects, it is important to understand if the poroelastic characteristics from such fields have been altered due to depletion. Among rock properties, Young’s modulus (E), bulk modulus (Kb) and Biot coefficient (α) are of particular importance. In this study, the poroelastic deformation of a core from the West Delta field in the Gulf of Mexico is characterized experimentally and the impacts of supercritical CO2 (scCO2) on the specimen are investigated. The experimental program simulated reservoir stress changes due to production-induced depletion and scCO2 injection through cycling both the confining pressure (Cp) and pore pressure (Pp). We measured the deviatoric stress, volumetric strain, derived the corresponding Young’s (E), bulk moduli (Kb) and Biot coefficient (α). The results show that the effect of scCO2 on E is more significant at greater confining pressures during the injection phase than depletion at a constant simple effective stress. Interaction of scCO2 with clay minerals caused rock frame dehydration and led to an increase in E. The bulk modulus increased with increasing the confining pressure at a given Pp and decreased with Pp at a certain Cp. α rose with Pp during both depletion and injection phases. Interaction with scCO2 limited the variation of α and the effect of Pp and Cp on α decreased in significance during the depletion phase. Longer interaction time with scCO2 increased α from 10-25% at different Pp values compared to argon during the injection stage. However, the influence of effective stress in reducing the α weakened.