Gas Storage Site Research Articles

Multidisciplinary assessment of seasonal ground displacements at the Hatfield Moors gas storage site in a peat bog landscape

The study aims to analyse ground displacement conditions observed over an Underground Gas Storage (UGS) site located at Hatfield Moors (United Kingdom), with a focus on understanding its implications for decarbonization efforts. The location serves as an active onshore storage site and was used as an analogy to assess ground motion implications around Carbon Capture and Storage (CCS) by the British Geological Survey (BGS) as part of the SENSE (Assuring integrity of CO2 storage sites through ground surface monitoring) project. Given the value of continuous and real-time monitoring of ground movements induced by gas storage activities, the study leverages satellite Interferometric Synthetic Aperture Radar (InSAR) data to assess the environmental impact of UGS operations. Using free and open-source Sentinel-1 satellite data, ground motion patterns over Hatfield Moors are analysed, highlighting displacements ranging from − 5.0 to -10.0 mm/year within the peat bog. In addition, the Time Series (TS) of ground displacement from January 2018 to December 2022 reveals a seasonality in ground motion, with uplift observed in late winter and subsidence in late summer, showing a periodicity of approximately 1 year and a magnitude of +/-10.0 mm. Through in-depth analysis, the study highlights the need to understand the underlying causes of ground fluctuations at gas storage sites. This paper shows that InSAR has the versatility to integrate seamlessly with different monitoring tools and methodologies, opening avenues for comprehensive and holistic analyses. Cross-correlation analyses further elucidate temporal relationships between different datasets by evaluating InSAR time series, UGS injection/withdrawal data and piezometric data. This involves decomposing the TS into distinct components, including trend, seasonality and residuals. The case of Hatfield Moors shows a significant discrepancy between the UGS data and the InSAR TS, while also demonstrating a clear correlation between the groundwater data and the InSAR TS. By integrating insights from geology, hydrology and remote sensing technologies, the study navigates the complexities inherent in areas of overlapping phenomena. Accurate interpretation is essential for informed decision making, particularly at sites such as Hatfield Moors, where the convergence of natural peat motion and storage operations highlights the need for interdisciplinary analysis to understand the underlying causes of ground fluctuation.

The role of the Messinian evaporites in the identification of potential gas storage sites: A review of the Adriatic foreland basin system (Italy)

AbstractFocusing on the late Miocene succession stratigraphic successions including the evaporite deposits from the Messinian salinity crisis (MSC) of the Adriatic foreland basin, a revision of available boreholes and seismic data allowed us to recognize the presence of reservoirs and seals systems that can be considered of potential interest for the storage of natural and synthetic gas. Potentially good reservoir sites can be found where porous rocks referable to siliciclastic turbiditites (Marnoso‐arenacea and Laga Fms) or shallow‐water carbonates (Bolognano Fm) preferentially involved in anticlinal structures and covered by thick MSC evaporites, which may represent effective reservoir seals. The integrated reconstruction of porous rocks distribution and facies, thickness, and lateral continuity of the overlying evaporites, allows the identification and zonation of geological settings in the Adriatic foredeep, backbulge and foreland with peculiar stratigraphy and deformations, only partially considered before, that may deserve consideration in the research of potential gas storage sites.

Influence of Fault Dip Angle and Strength on Fault Slip Characteristics of Gas Storage

The alternating stress caused by periodic high-pressure injection and extraction in gas storage can potentially induce fault slippage, compromising the sealing integrity of faults within these storages sites. Understanding the mechanical behavior of faults under alternating stress is crucial for ensuring the long-term stability and safety of gas storage operations. To explore the impact of fault dip angle and fault gouge strength on fault slip characteristics, fault samples were prepared with uniaxial compressive strengths of 20.1, 30.2, 42.4, and 51.4 MPa at two distinct dip angles. Triaxial compression experiments were conducted under alternating stress conditions corresponding to operational pressures at a specific gas storage site in China. The results indicate that faults with dip angles of 30° and 45° tend to fail at their weakest points. The increasing strength of fault gouges shifts failure mechanisms from interfacial failure between gouges and the surrounding rock towards internal gouge failure, often accompanied by shear failure across sections, resulting in characteristic “X”-shaped conjugate shear failures. The decrease in the ratio of bedrock strength to fault gouge strength elucidates the observed phenomena of an initial reduction followed by increased fault deformation. Transition points for faults with 30° and 45° dips occur around the strength ratios of 1.7/1 and 1.2/1, respectively. Fault damage exhibits a negative correlation with fault gouge strength and a positive correlation with fault dip angle. Samples with a higher-strength fault gouge at a 30° dip angle generally incur less damage compared to those with a lower-strength fault gouge at a 45° dip angle. Moreover, higher maximum static friction coefficients denote greater fault resistance to slipping, with 30° faults consistently demonstrating superior resistance compared to 45° faults. Additionally, a higher-strength fault gouge consistently enhances slip resistance under identical dip angles.

Interactions at the interfaces of the H2-brine-cement systems at elevated pressures for H2 storage

There is a global demand on assessment of potential subsurface gas storage sites in view of safely injecting hydrogen or carbon dioxide. One relevant aspect that has already been subject to thorough investigation is the mutual interaction of all participating compounds in terms of the wetting behaviour that on its turn is directly related to the predominating capture mechanisms. Given the diversity of the geophysical and geochemical circumstances, transferability of results from work conducted on one geological site to another location is limited. For instance, there is a large number of publications on wettability of many different rock types in hydrogen atmosphere that are partly controversal and strictly applicable only to the respective reported system. Hence, there is a gap in finding general model approaches that serve for a holistic understanding of predominating mechanisms and building the fundamentals for predicting the behaviour of systems that have not been studied so far. The presented work addresses this gap by quantifying mutual interactions of the participating phases in a solid-liquid-gas systems and determining the respective interfacial tensions, γSV (solid-vapor), γLV, (liquid-vapor) and γSL (solid-liquid).Neumann and Good demonstrated how to determine the solid-fluid interfacial tension based on the contact angle and the liquid-gas interfacial tension by calculating a so-called molecular interaction parameter. Up to date, this method has been applied, among others, for systems containing CO2 and solids such a teflon, glass, and steel. The methodology could be confirmed by testing systems comprising steel - H2O - CH4 /H2 and comparing the results to the aforementioned literature data.As one of the critical parts in H2 underground storage, the completion system containing a common well cement, H2 and brine was subject to this work. The interfacial tension between H2 and brine as well as the contact angle between the fluid phases and the cement were investigated experimentally up to 20 MPa, temperatures from 313.15 to 353.15 K and NaCl – concentrations of up to 10% wt. As a theoretical approach, the interfacial tension of the system H2O+H2 was investigated using the density gradient theory (DGT) in combination with the perturbed chain statistical associating fluid theory equation of state (PC-SAFT). Finally, the H2-cement interfacial tension is determined through the calculation of a so-called molecular interaction parameter. The interfacial tension data of H2O+H2 experimentally and theoretically determined in this work agree among each other as well as with previous literature data. Likewise, agreement was found between the brine+H2 interfacial tension and previous studies. The contact angle appears to be influenced mostly by pressure, producing a less H2O/brine-wet system as pressure increases. The H2-cement interfacial tension decreases from approximately 150 mN/m down to 100 mN/m, as the pressure increases from 0.1 to 20 MPa. The presented data suggest H2 to be slightly adsorbed on the one hand but the capillary entry pressure to decrease on the other, causing concerns regarding the integrity of the completion system.

The influence of an anticline structure on ambient noise spectral anomalies at an underground gas storage

SUMMARY The purpose of this study is to investigate the seismic ambient noise spectral anomalies that occur near gas reservoirs. These anomalies involve a significant spectral amplification of the vertical component for frequencies generally between 1.5 and 4 Hz and have been reported at various hydrocarbon sites worldwide. There are differing views on the mechanisms responsible for these anomalies. The guideline for this study is that many hydrocarbon reservoirs share a common geological feature: an anticline structure. It appears to cause site effects that influence the amplitude of the ambient noise wavefield. This research examines a dense real data set of ambient noise recorded at the Chémery underground gas storage site in France. The analysis identifies stable spectral anomalies between 1.2 and 2.4 Hz that are correlated to the position of the anticline structure, which also corresponds to the position of the gas bubble. We use a beamforming technique to study the composition and the origin of the ambient noise, and show that the variations of the spectral anomalies over time are correlated to changes in the source wavefield. Finally, we perform numerical simulations of Rayleigh wave propagation within a realistic 3-D velocity model of the Chémery site, while using source distributions directly extracted from real data analysis. The comparison of the simulated anomalies with real data yields a satisfactory qualitative fit. We conclude that the fundamental-mode Rayleigh wave site effect on the anticline is the main mechanism of the spectral anomaly.

High-resolution geoelectrical characterization and monitoring of natural fluids emission systems to understand possible gas leakages from geological carbon storage reservoirs

Gas leakage from deep geologic storage formations to the Earth’s surface is one of the main hazards in geological carbon sequestration and storage. Permeable sediment covers together with natural pathways, such as faults and/or fracture systems, are the main factors controlling surface leakages. Therefore, the characterization of natural systems, where large amounts of natural gases are released, can be helpful for understanding the effects of potential gas leaks from carbon dioxide storage systems. In this framework, we propose a combined use of high-resolution geoelectrical investigations (i.e. resistivity tomography and self-potential surveys) for reconstructing shallow buried fracture networks in the caprock and detecting preferential gas migration pathways before it enters the atmosphere. Such methodologies appear to be among the most suitable for the research purposes because of the strong dependence of the electrical properties of water-bearing permeable rock, or unconsolidated materials, on many factors relevant to CO2 storage (i.e. porosity, fracturing, water saturation, etc.). The effectiveness of the suggested geoelectrical approach is tested in an area of natural gas degassing (mainly CH4) located in the active fault zone of the Bolle della Malvizza (Southern Apennines, Italy), which could represent a natural analogue of gas storage sites due to the significant thicknesses (hundreds of meters) of impermeable rock (caprock) that is generally required to prevent carbon dioxide stored at depth from rising to the surface. The obtained 3D geophysical model, validated by the good correlation with geochemical data acquired in the study area and the available geological information, provided a structural and physical characterization of the investigated subsurface volume. Moreover, the time variations of the observed geophysical parameters allowed the identification of possible migration pathways of fluids to the surface.

THE UPPER PERMIAN ZECHSTEIN SUPERGROUP OF NE ENGLAND AND THE ADJACENT SOUTHERN NORTH SEA: A REVIEW OF ITS ROLE IN THE UK'S ENERGY TRANSITION

As the United Kingdom reduces its CO2 emissions in order to meet its 2050 net zero greenhouse gas targets, there will be a significant evolution of the UK's energy mix. The reliance on hydrocarbons will decrease while there is predicted to be an increase in low carbon energy sources such as renewables and nuclear. In order to decarbonise and achieve the net zero emissions targets while concurrently producing enough energy to provide for national energy needs, large‐scale, low carbon energy generation projects need to be developed alongside energy storage facilities to provide flexibility within a low carbon energy supply. Robust CCUS programmes will need be developed in order to capture and store unavoidable carbon dioxide emissions. The subsurface geology of the UK provides opportunities for the development of low carbon energy generation, energy storage and CCS, and the Upper Permian Zechstein Supergroup deposited in eastern England and offshore in the Southern North Sea is a potential host for these new developments. In NE England, salt cavern gas storage sites have been developed in thick Zechstein evaporites since the mid 20th centrury. In this paper we present new isopach maps and well correlation panels which will help to outline optimal locations for the development of additional salt caverns for gas storage. A review of the Zechstein Supergroup indicates that it does not exhibit great potential for the development of CCS, due both to its complex reservoir characteristics and to difficulties with both subsurface imaging and monitoring. However thick Zechstein evaporites could provide an excellent seal for CO2 storage in the underlying Lower Permian Rotliegend Group.

Integrating underground gas storage experience for CCS optimisation

Carbon capture and storage (CCS) sites require diligent assessments to account for potential leakage over time. Leakage pathways include both natural and engineered (e.g. wells) invoking the requirement for a structured technical analysis as part of a risk inventory. This paper focuses on lessons learnt from underground gas storage (UGS) sites to guide CCS technical workflows to handle natural geological risk elements. UGS facilities have been operating for over a 100 years. Their injection and withdrawal histories, by their very nature, test the complex changes that occur to the reservoir and cap-rock over time and provide valuable insight to demonstrate the feasibility of CCS and its potential for long-term storage. Geomechanical assessment of the reservoir and cap-rock requires an inventory of core material, log and seismic data with the aim of selecting the appropriate data to model the ability of that formation to contain a column of CO2. As supercritical CO2 is injected into the formation and pore pressure builds, the geomechanics of the reservoir needs diligent review to assess the potential to trigger failure on the cap-rock and pre-existing faults and fractures. UGS injection/withdrawal histories assist in the reservoir and overburden static and dynamic modelling along with designing a measurement, monitoring and verification process for CCS sites. Technical workflows, from seismic and static modelling to geomechanics and dynamic simulation and back to seismic for containment monitoring, are discussed that have been refined by UGS experience to benefit the selection of potential CCS sites.

Perspectives on geologic carbon storage

Geologic carbon storage (GCS) is a fundamental pillar of carbon management that helps mitigate greenhouse gas emissions and addresses the negative effects of climate change. Viable CO2 storage sites share some of the same elements required for successful petroleum systems. For example, while reservoir, seal, and trap are required, migration pathway and timing are not important for CO2 storage, because rather than withdrawing fluid from a trap, CO2 storage involves injection into a geologic trap. Conceptually, this represents a form of reverse production. Numerous petroleum traps around the world, as well as naturally occurring CO2-producing fields and natural gas storage sites attest that safe, long-term storage is possible. Research over the past two decades identified five methods of Geologic Carbon Storage which have been validated through several demonstration and pilot projects around the world: (1) storage in depleted oil and gas fields, (2) use of CO2 in enhanced hydrocarbons recovery (3) storage in saline formations/aquifers, (4) injection into deep unmineable coal seams, and (5) in-situ/ex-situ carbon mineralization. The greatest volumetric potential for GCS is found in saline aquifers which are present throughout the world’s sedimentary basins.

Application of hybrid artificial intelligent models to predict deliverability of underground natural gas storage sites

Underground natural gas storage is a promising solution to lowering greenhouse gas emissions and attaining sustainable development goals. However, several issues prevent the application of storage projects on a global scale. An accurate estimation of the delivered amount of natural gas from each storage site might be used for supply and demand. Due to this fact, this study proposed hybrid intelligent models integrating the least square support vector machine (LSSVM), differential evolution (DE), imperialist competitive algorithm (ICA), cultural algorithm (CA), teaching learning-based optimization (TLBO), genetic algorithm (GA), and particle swarm optimization (PSO) for approximating the deliverability of underground natural gas storage in different geological formations. We have employed vast data sets of 782 reservoirs from depleted fields to train and validate the proposed intelligent models to predict underground natural gas storage deliverability in the USA. The visual and analytical assessments were used to investigate the performance of the developed intelligent systems. The predicted results showed that all of the intelligent models agreed with the recorded data. Moreover, the statistical indicators revealed that the LSSVM coupling TLBO model shows the highest accuracy in predicting the deliverability of natural gas storage in the depleted field among three intelligent models. Also, the optimal intelligent model accurately predicts 880 and 600 data measurements of saline aquifers and salt domes, respectively. The optimal intelligent model yields a root mean square error (RMSE) value of less than 0.022. The correlation factor (R2) is over 0.998, 0.999, and 0.906 for the depleted field, saline aquifers, and salt domes, respectively. The results highlight the importance of combining smart approaches with nature-inspired strategies in forecasting storage site deliverability. In light of these findings, researchers are better equipped to reduce petroleum energy usage and increase community acceptability of natural gas as part of the transition to green energy.

Mechanical behavior of salt rocks: A geomechanical model

The geomechanical behavior of salt rocks is a significant concern during drilling and development operations in some hydrocarbon reservoirs and underground gas storage sites. In this study, the static and dynamic salt rock geomechanical properties from a field in southwest Iran were evaluated using experiments such as waves' velocities, and thermo-mechanical coupled uniaxial and triaxial compression tests. As a result and by considering both the petrophysical well logs and laboratory data of the waves’ velocities, it is observed that the elastic properties of the core samples are concentrated within a narrow range unless an abnormality causes scatter. The results of uniaxial compression tests showed that rock strength decreases with increasing temperature linearly. In addition, the reduction of rock strength was observed with increasing porosity of the core samples as expected. In the case of triaxial compression tests, applying confining pressure on the core sample caused an increment in rock strength, while temperature decreased rock strength. The temperature also increased cohesion and decreases friction angle. The ratio of changes in stress to strain was used to investigate the dynamic changes in the geomechanical state. The maximum 0.25 damage factor was observed for the core samples for different definitions of the damage factor. Finally, we propose a novel analytical model to predict the stress-strain behavior of salt rocks at different conditions. The model was validated using experimental results and indicated a satisfactory accuracy.

Dynamic Sealing Behavior of Sand Self-Juxtaposition Windows on a Trap-Bounding Fault in a Natural Gas Storage Site

Abstract An understanding of across-fault seals is essential for planning an injection/production strategy for a fault-bounded gas storage site. In addition, it is more likely to permit lateral leakage for a fault with sand self-juxtaposition windows. This paper is aimed at identifying the dynamic sealing behaviors of a sand self-juxtaposition fault on the geological and gas injection timescales. Banzhongbei gas storage site, China, was taken as a target area, and fault seals and hydrocarbon distributions within the original reservoirs were studied. The results showed that across-fault pressure differences of 0.085~0.146 MPa (equivalent to 41.6~71.5 m oil-column and 27.0~46.4 m gas-column heights) were supported by sand self-juxtaposition windows on the B816 fault, and the resultant absolute permeability (5.97×10−2~5.69×10−1 mD) of the fault was nearly 3~4 orders of magnitude lower than the average absolute permeability of reservoirs (1.16×102 mD). Gas composition contrasts, between the original and injection gas coupled with dynamic pressure monitoring data, indicated that lateral leakage occurred across sand self-juxtaposition windows under the condition of high across-fault pressure difference. However, the low-permeability fault showed strong negative influence on the efficiency of fluid flow in the model calculations and prolongs the timescales of pressure-difference decayed as much as 5 orders of magnitude relative to those of nonfault model calculations. These modeled dynamic sealing behaviors of sand self-juxtaposition windows may lead to a better understanding of the relative retardation of across-fault gas flow by weak sealing faults on the gas injection/production timescale.

Knowledge-based rigorous machine learning techniques to predict the deliverability of underground natural gas storage sites for contributing to sustainable development goals

This study presents a method to develop a series of unique deliverability smart models for underground natural gas storage (UNGS) in different types of target formations. The natural gas supply loop is defined by periodic mismatches between demand and supply. Efficient and faster approaches for forecasting UNGS deliverability may not only assist stakeholders but also the competitive natural gas industry. Due to this fact, this article suggests a series of robust deliverability estimation models for 387 UNGS sites in depleted fields, aquifers, and salt domes based on rigorous machine learning (ML) techniques. To this end, the potential of three ML algorithms, including Gaussian Process Regression (GPR), Least Squares Support Vector Machine (LSSVM), and Extra Tree (ET), is employed. To assess and compare the proposed models, statistical parameters including coefficient of determination (R2), root mean square error (RMSE), mean absolute error (MAE), and standard deviation (SD) were employed. Accordingly, in the case of depleted fields, the GPR, LSSVM, and ET paradigms show overall R2, RMSE, and MAE of 0.999999998, 4.75E−06, 0.00021, and 0.00021. For salt domes, the GPR, LSSVM, and ET models indicate overall R2, RMSE, and MAE of 0.987, 0.0046, and 0.11. Finally, for aquifers, the GPR, LSSVM, and ET algorithms represent overall R2, RMSE, and MAE of 0.999999997, 7.1094E−06, and 0.0002102. The prediction performance reveals that the GPR model is superior to the LSSVM and ET models. This study found that the proposed intelligent models could be utilized as a template for fast estimating the deliverability of UNGS in depleted fields, aquifers, and salt domes with high accuracy. In the end, the outcomes of this study contribute to a deeper understanding of the critical role of machine learning in resolving the difficulty of forecasting the UNSG on cleaner production and sustainable development strategies.

Subsidence above gas storage in salt caverns predicted with viscoelastic theory

Based on the on-site monitoring data, the surface subsidence in the Jintan underground gas storage site has occurred continuously since the construction and operation of gas storage engineering. Therefore, the prediction of surface subsidence above gas storage in salt caverns is important to ensure the long-term safety of gas storage. Based on the mechanics theory, the formulas of elastic deformation of spherical and cylindrical caverns are derived. The Burgers viscoelastic model is used to describe the creep of rock salt. The viscoelastic analytical solution of the cavern deformation is obtained by using the correspondence principle in viscoelastic theory. It is assumed that the volume of the surface subsidence basin is directly proportional to the shrinkage volume of the cavern. The surface subsidence distribution curve is described by a Gaussian function. The spatiotemporal prediction of surface subsidence above gas storage in salt caverns based on viscoelastic theory is thus developed. The proposed theoretical model is used to analyze the surface subsidence above a gas storage cavern in rock salt in Jintan. The calculated subsidence is compared with the monitoring data. The accuracy of the theoretical model is verified by numerical simulation. The theoretical model can be used to predict the surface subsidence considering the solution stage in which the internal pressure changes with time. Results of this paper can provide guidance and suggestions for engineering practice of gas storage in salt caverns.

Monitoring the Microseismicity through a Dense Seismic Array and a Similarity Search Detection Technique: Application to the Seismic Monitoring of Collalto Gas-Storage, North Italy

Seismic monitoring in areas where induced earthquakes could occur is a challenging topic for seismologists due to the generally very low signal to noise ratio. Therefore, the seismological community is devoting several efforts to the development of high-quality networks around the areas where fluid injection and storage and geothermal activities take place, also following the national induced seismicity monitoring guidelines. The use of advanced data mining strategies, such as template matching filters, auto-similarity search, and deep-learning approaches, has recently further fostered such monitoring, enhancing the seismic catalogs and lowering the magnitude of completeness of these areas. In this framework, we carried out an experiment where a small-aperture seismic array was installed within the dense seismic network used for monitoring the gas reservoir of Collalto, in North Italy. The continuous velocimetric data, acquired for 25 days, were analysed through the application of the optimized auto-similarity search technique FAST. The array was conceived as a cost-effective network, aimed at integrating, right above the gas storage site, the permanent high-resolution Collalto Seismic Network. The analysis allowed to detect micro-events down to magnitude Ml = −0.4 within a distance of ~15 km from the array. Our results confirmed that the system based on the array installation and the FAST data analysis might contribute to lowering the magnitude of completeness around the site of about 0.7 units.

Water quality control in a water curtain system at an underground rock cavern of liquefied petroleum gas storage site (Kurashiki, Japan)

Water quality control in a water curtain system at an underground rock cavern of liquefied petroleum gas storage site (Kurashiki, Japan)

Assessment of oil and gas fields in California as potential CO2 storage sites

California's total annual greenhouse gas (GHG) emissions (425.3 MtCO2e) in 2018 were about 6.4% of the US total (6,677 MtCO2e) and around 1% of global emissions. About 39% of 2018 GHG emissions in California were from the industrial and electrical sectors. Many of these emissions were from large stationary point sources and were suitable for carbon capture retrofit with subsequent storage of the captured carbon dioxide (CO2) in geological formations. Previous studies of California found suitable geology and CO2 storage resource. This study refines and furthers prior work using a three-stage screening process of oil fields, gas fields, and underground natural gas storage (UGS) sites by combining criteria from previous studies while excluding sites that pose technical risk or are located in regions with surface restrictions including sensitive habitats and dense populations. In the first stage, 129 CO2 storage sites in California were identified using qualification criteria based upon formation properties including geological conditions and pore pressure. The second stage identified sensitive sites by applying conservative screens including seismic activity, faulting, population density, restricted lands, and sensitive habitats. During the third stage, 61 CO2 potential storage sites were identified by subtraction of stage 2 areas from stage 1. The potential storage volume in the third stage ranged from 1.0 to 2.0 GtCO2. Finally, we applied a scoring system with seven parameters to rank the 61 potential sites based on subsurface technical criteria. The scored sites are classified as high priority, medium priority, and sites for future study. Prospective CO2 storage sites with high and moderate priority were selected and linked to CO2 sources. There are 14 prospective sites (above 20 MtCO2 storage resource per site) with a total storage resource of 1024 MtCO2 distributed in Northern and Southern California. Of these sites, there are 9 potential CO2-EOR sites and 1 depleted oil field with a total estimated CO2 storage volume of ∼800 MtCO2 in the Southern San Joaquin and Ventura Basin. These 10 prospective sites with a storage resource greater than 20 MtCO2 could potentially deliver more than 20 years of storage with an average injection rate of 40 MtCO2/year. The remaining 4 highly prospective sites are in Northern California. Study results also suggest that saline formations should be re-evaluated in concert with storage in oil, gas, and natural gas storage reservoirs.

Monitoring geological gas storage sites with ambient noise interferometric methods: focus on seismic attenuation changes for gas movement detection.

Monitoring geological gas storage sites with ambient noise interferometric methods: focus on seismic attenuation changes for gas movement detection.

Fault Mapping of the Gassum Formation Reservoir and the Fjerritslev Formation Caprock Interval at the Stenlille Gas Storage Site Using a Pre-Trained Convolutional Neural Network

Fault Mapping of the Gassum Formation Reservoir and the Fjerritslev Formation Caprock Interval at the Stenlille Gas Storage Site Using a Pre-Trained Convolutional Neural Network

Diagnostic and predictive analysis of production and injection‐induced fault activation

AbstractMitigating the hazard of fault reactivation during CO injection and oil production is important for ensuring environmental sustainability of geologic carbon sequestration and hydrocarbon recovery. Currently, we do not know how the Coulomb Failure Stress (CFS), which is a commonly used metric to assess the potential of inducing slip on a fault, evolves differently for gas injection and oil production scenarios. Using high‐resolution simulations of CO injection‐induced and oil production‐induced fault slip and theories of Coulomb failure and poroelasticity, we address this gap in knowledge. We analyze the fault tractions, slip, and reservoir pressure to understand how a fault is destabilized in successive steps, how hypocenter locations are selected, and how these processes differ between injection and production. We extract and summarize the characteristic features of induced fault activation in terms of the dependence of CFS and the Fault Stress Ratio (FSR) on the dimensionless reservoir pressure perturbation caused by injection or production. We apply the framework to the Farnsworth oilfield in Texas, which is undergoing CO injection and oil production, to disambiguate observations related to fault stability. Finally, we discuss how our framework can inform models that aim to forecast fluid flow‐induced slip and mitigate the induced seismicity hazard in oilfields and gas storage sites.