The injection of produced water back into producing permeable formations is regarded to be of low risk of inducing earthquakes because injection into producing conventional reservoirs generally does not lead to a net increase in reservoir pressure. The rise of production from tight unconventional reservoirs, on the other hand, required injection into non-producing aquifers. While unsurprising in hindsight, the concomitant increase in induced seismicity was unexpected based on the assumption, later shown to be false, that faults in stable cratonic sedimentary basins such as those in Texas and Oklahoma are not critically stressed. Complicating matters more, seismicity preferentially occurred in crystalline basement well below the injection target. Geomechanical models demonstrate that this response can be attributed to poroelastic stresses that are active over a larger distance and greater depth than the direct pore pressure disturbance. Our fully coupled poroelastic finite element simulations also demonstrated that in basins of large-volume injection, stress changes cannot be attributed to a single well or injection operation but reflect the cumulative effect of multiple disposal and production wells on a regional scale, making mitigation significantly more challenging. The difficulty of hindcasting observed seismic events on known and well-instrumented faults also demonstrated that effective forecasting of a seismic response would be difficult. This presentation will discuss viable approaches to mitigating the induced seismicity risk, concluding that active pressure management and avoiding injection in close vicinity to known large faults or close to infrastructure are perhaps the most effective approaches for mitigating earthquake risk associated with large-volume injection of wastewater and CO2 into aquifers.

Our understanding of fault mechanics and earthquake processes remains limited, largely due to minimal direct observations near active faults at seismogenic depths. This lack of data restricts our ability to accurately assess and mitigate both natural and human-induced seismic hazards. However, recent advancements in drilling capabilities and downhole sensing technologies offer an opportunity: the ability to observe the physical conditions within a volume near active fault zones. In this contribution, we highlight how scientific drilling can provide access to the near-fault environment, enabling measurements of the stress, temperature, fluid pressure, and rock properties at depths where ruptures initiate, propagate, and arrest. These observations are essential to refine models of earthquake nucleation and dynamic rupture, bridging gaps between laboratory experiments, numerical simulations, and surface observations. These insights can advance fundamental understanding in earthquake science but also support the development of more effective seismic hazard assessments and risk mitigation strategies.

This study aims to establish a comprehensive framework for evaluating the geothermal potential of High-Pressure and High-Temperature (HPHT) aquifers or geopressured geothermal reservoirs in the Wilcox Formation on the onshore Gulf Coast of Texas, USA. The framework integrates geological and engineering approaches to determine the feasibility and viability of harnessing geothermal energy from these aquifers. By considering geological features and reservoir properties, such as heat capacity and thermal conductivity of fluid and rock, fluid flow dynamics, and heat losses in the wellbore and through the under and overburden, this integrated framework will provide valuable insights for the sustainable production of geothermal resources from the onshore Wilcox aquifers.

The El Paso (TX)–Ciudad Juárez (MX) metropolitan area, located within the tectonically active Rio Grande Rift, has historically recorded shaking from nearby high-magnitude earthquakes (e.g., the 1887 Mw 7.6 in Sonora, MX, and the 1931 Mw 5.8 in Valentine, Texas). Application of the machine-learning (ML)-based EarthQuake Compact Convolutional Transformer (EQCCT) algorithm to seismic data from 2008 to 2011 resulted in the detection of 645 seismic events in the area, lowering the magnitude detection threshold compared to public catalogs (e.g., U.S. Geological Survey ComCat with 35 events in the same period). Manual review and relocation using NonLinLoc and hierarchical clustering with GrowClust3D revealed seven seismic clusters: four clusters align with mapped Quaternary faults, whereas three clusters correspond to previously unrecognized seismogenic structures. These results demonstrate that advanced ML techniques can enhance earthquake detection and refine the understanding of regional seismicity. With new geothermal projects on the horizon in West Texas, the enhanced seismic catalog provides a more robust basis for assessing seismic hazard potential, which is critical for guiding safe geothermal development in the region.

Numerous surface-felt earthquakes have been spatiotemporally correlated with hydraulic-fracturing operations. Because large deformations occur close to hydraulic fractures (HFs), any associated fault reactivation and resulting seismicity must be evaluated within the length scale of the fracture stages and based on the precise fault location relative to the simulated rock volumes. To evaluate the changes in Coulomb failure stress (CFS) with injection, we conduct fully coupled poroelastic finite-element simulations using a pore-pressure cohesive zone model for the fracture and fault core in combination with a fault-fracture intersection model. The simulations quantify the dependence of CFS and the fault reactivation potential on the host rock and fault properties, spacing between the fault and the HF, and the fracturing sequence. We find that fracturing in an anisotropic in-situ stress state does not lead to fault tensile opening but rather dominant shear reactivation through a poroelastic stress disturbance over the fault core ahead of the compressed central stabilized zone. In our simulations, poroelastic stress changes significantly affect fault reactivation in all the simulated scenarios of fracturing 50–200 m away from an optimally oriented normal fault. Asymmetric HF growth due to the stress shadowing effect of the adjacent HFs leads to (1) a larger reactivated fault zone following the simultaneous and sequential fracturing of multiple clusters compared with single-cluster fracturing and (2) a larger unstable area ([Formula: see text].1) over the fault core or a higher potential of the fault slip following sequential fracturing compared with simultaneous fracturing. The fault reactivation area is further increased for a fault with lower conductivity and a higher opening-mode fracture toughness of the overlying layer. To reduce the risk of fault reactivation by hydraulic fracturing under the reservoir characteristics of the Barnett Shale, Fort Worth Basin, it is recommended to (1) conduct simultaneous fracturing instead of sequential and (2) maintain a minimum distance of approximately 200 m for HF operations from known faults.

Fractured crystalline basement reservoirs are of increasing economic interest for oil and gas exploration and subsurface fluid storage. The successful characterization of these reservoirs is commonly challenged by their structural heterogeneity, complexity in fracture distribution and flow properties at multiple scales, and the difficulty of imaging fractures in exploration seismic. We analyzed the fracture geometry and fracture diagenetic attributes in two oriented cores from the Habban Field in the Late Jurassic Sab'atayn Basin (Yemen) to evaluate the multi-phase deformation history and fracture flow pathway evolution for (hydrothermal) fluids and hydrocarbons. Analyses included petrographic and fluid inclusion analysis of fracture-filling cements, and stable sulfur isotope analyses of fracture-filling pyrite. The Paleoproterozoic basement consists of amphibolite-facies metamorphic ortho- and paragneiss cut by several phases of Neoproterozoic granitoid intrusions. The investigated lithologies in the drill cores comprise (1) epidote quartzite, (2) amphibolite, (3) monzogranite, (4) meta-arkose, and (5) quartz-feldspar porphyry. These lithologies show an inhomogeneous fracture network that is partially cemented. Ediacaran brittle-ductile deformation (D1) recognized only within a Pan-African monzogranite lead to cataclasis and porosity generating alteration. Late Jurassic - Early Cretaceous extension (D2) related to the break-up of Gondwanaland and the formation of the Sab'atayn Basin is found in all lithologies and likely resulted in pervasive quartz cementation. Late Jurassic fractures parallel to the NW-SE trending long axis of the Sab'atayn Basin are best recognized in a strongly foliated amphibolites. Cenozoic extensional fracturing (D3) reactivated older structures, which probably formed during activity of the Neoproterozoic Najd Fault System and caused multi-phased (pyrite(saddle) dolomite-calcite) fracture cementations. The sulfur isotope compositions of pyrite with delta S-34 values ranging between -17.4 and + 26.4 parts per thousand vs. V-CDT reflects the variability of the fluid source during sulphide mineral formation from hydrocarbon-rich hydrothermal solutions. Fluid inclusions indicate that cementation reactions occurred in a relatively narrow temperature field between 120 degrees C and 140 degrees C, ideal for hydrocarbon maturation. Our results demonstrate the potentially complex charge history of basement reservoirs, involving multiple phases of fracture formation and cementation, and fluid charge episodes.

Natural fractures are generally viewed as elliptical in shape, consistent with elastic fracture mechanics. To quantify deviations of fracture shape from theoretically predicted elliptical opening distributions and to evaluate processes leading to non-elliptical fracture shapes, we measured aperture profiles of quartz-cemented opening-mode fractures in low-grade metamorphic sandstone. Ellipticity was quantified by the Lamé n-value, with measured n-values deviating significantly from n=2 for elliptical shapes, ranging from 0.7 for tapered fractures to 3.2 for blunted fractures.While some deviation from n=2 can be explained by mechanical interaction with nearby fractures and layer boundaries, we explain the generally observed large variation in n values with competing processes between chemically assisted subcritical fracture propagation, leading to preferred fracture length growth and tapered tips for non-recoverable inelastic fracture opening by solution-precipitation creep, and preferred aperture growth and tip blunting by locally enhanced solution-precipitation creep in the fracture tip region. Using geometric models, we show that preferred length growth with non-recoverable fracture opening strain can lead to tapered fractures with n=1; Preferred aperture growth and opening increments with Lamé n=3 result in overall blunted fracture shapes with n>2. We propose that fracture ellipticity provides a measure of chemically reactive fracture growth processes in geological systems.

Natural fractures in shale and sandstone that formed under diagenetic and metamorphic conditions are frequently filled with mineral cement that lack residual fracture porosity visible under the petrographic microscope and that are generally interpreted to be impermeable. Scanning electron microscopy of calcite, dolomite, quartz, and barite fracture cement from low-permeability, diagenetically altered shale and sandstone formations provides evidence of open and variably connected elongate pores or gaps with apertures of 10-600 nm, referred to as nanoscale grain boundary channels (NGBC). Electron backscatter diffraction of samples prepared using broad ion-beam milling shows that NGBCs occur along grain boundaries of blocky or columnar fracture cement. Grain boundaries are either faceted or display undulation at the nanometer scale. NGBCs tend to increase in aperture with increasing maximum formation burial temperature, indicating dissolution-precipitation kinetics influences grain boundary structure. Transmission electron microscopy reveals heterogeneous crystallographic domains with possible amorphous regions bridging across grain boundary channels. We propose a model of dynamic concurrent dissolution-precipitation along grain boundaries that preserves NGBCs in carbonate and quartz fracture cements that have experienced diagenetic to low-grade metamorphic conditions. While partially healed, NGBCs may be sufficiently connected to increase permeability of low-permeability formations containing cemented fractures.

Arrays of natural opening-mode fractures show systematic patterns in size and spatial arrangement. The controls on these factors are enigmatic, but in many cases the depth of formation appears to be critical. Physical, potentially depth-dependent factors that could account for these variations include confining stress, fluid pressure, and strain rate; these factors are common inputs to existing fracture models. However, temperature-dependent chemical processes likely exert an equally important control on patterns, and such processes have not yet been rigorously incorporated into models of fracture formation. Here we present a spring-lattice model that simulates fracturing in extending sedimentary rock beds, while explicitly accounting for cementation during opening of fractures, and for rock failure via both elastic and time-dependent failure criteria. Results illustrate three distinct fracturing behaviors having documented natural analogs, which we here term fracture facies. “Exclusionary macrofracturing” occurs at shallow levels and produces large, widely spaced, uncemented fractures; “multi-scale fracturing” occurs at moderate depth and produces partially cemented fractures having a wide range of sizes and spacings; and “penetrative microfracturing” occurs at great depth and produces myriad narrow, sealed fractures that are closely and regularly spaced. The effect of depth is primarily to accelerate both dissolution and precipitation reactions via increased temperature and porewater salinity; the specific depth range of each fracture facies will vary by host-rock lithology, grain size, strain rate, and thermal history.

Fractures control heat and mass transfer and rheology in a wide range of subsurface regimes, ranging from low‐temperature diagenetic environments to high‐temperature metamorphic and magmatic systems. To investigate processes of opening‐mode fracture growth at high homologous temperature, we conducted constrained high‐temperature sintering experiments of thin layers of porous jadeite and quartz aggregate attached to a non‐sintering mullite substrate. Samples were heated stepwise at a low rate in a muffle furnace from 25°C to 1,000°C under ambient air pressure and examined for changes in mineral composition, texture, porosity, and fracture morphology using powder‐X‐ray diffraction, macro‐photography, reflected incident light microscopy, and secondary electron microscopy. Mineral reactions in the jadeite and quartz sample layer include jadeite and quartz reacting to albite at 600°C and the formation of nepheline and orthoclase at 900°C and 1,000°C. Opening‐mode fractures are first observed at 850°C coincident with the first presence of a melt phase with low aperture‐to‐length ratios similar to elastic‐brittle fractures. At 900°C, melt becomes increasingly abundant, and fractures obtain ductile morphology with high aperture‐to length ratios and blunted tips resulting from fracture growth by growth and coalescence of larger pores at the expense of smaller pores. In the absence of an externally applied mechanical load, we conclude that fracture growth is driven primarily by sintering stress resulting from differential contraction between sample layer and substrate associated with high‐temperature mineral reactions, melt formation and redistribution, and changes in pore structure. Similar fracture processes may be relevant to the segregation and migration of melt in magmatic systems.

The combined effects of oil and gas production and saltwater disposal in stacked reservoirs can result in poroelastic-stress changes that affect fault stability and induced seismicity but that are not captured by models that consider disposal only. While the significance of these combined effects has been demonstrated in site-generic geomechanical simulations, their significance is yet to be quantified for specific sites of observed induced seismicity. We conducted 3D monolithically coupled poroelastic finite-element simulations for a site-specific geomechanical analysis to assess the potential for reactivation of basement-rooted faults in response to saltwater injection and hydrocarbon production near Venus, Johnson County, Texas. Earthquake activity with magnitudes as high as Mw 4.0 primarily occurred in the basement section of a listric normal fault extending from basement across the Ellenburger disposal reservoir and into the overlying gas-producing Barnett Shale. We find that using the best estimates of in-situ stress and fault orientation, and fault frictional coefficient of 0.6, do not hindcast fault reactivation. Increasing the maximum horizontal stress azimuth by 10° and the basement fault dip by 5°, both within the uncertainty space of the input parameters, and lowering the friction coefficient of the fault in basement to 0.35, leads to fault reactivation in basement. Using the same model geometry but a friction coefficient of 0.6 leads to fault reactivation within the Ellenburger disposal reservoir, which is inconsistent with observed hypocenter depths. Including the effects of production from Barnett reduces the potential for fault reactivation compared to simulations of disposal only. Comparing simulations with only five disposal wells to results of simulating 35 wells, we demonstrate the sensitivity of fault reactivation to selected number of wells. In addition to showing the sensitivity of simulation outcomes on the availability of high-quality field parameters, these results demonstrate the need for coupled poroelastic simulations unlike common hydrogeological and reservoir engineering simulations that may significantly over- or under-estimate the potential for fault reactivation and thus for induced-seismicity hazard.

Relative timing of fracturing is a key input for predictive fracture models, but timing information for fractures is commonly diffi-cult to obtain. In this study, we used crosscutting relations and fluid inclusion assemblage temperatures from fracture cements from a few well-documented sampled fractures, combined with a one-dimensional burial history model, to establish timing for three generations of opening-mode fractures in a Barnett Shale core from the southern part of the Delaware Basin, Pecos County, West Texas. A burial history model is presented for the cored well and matched to measured vitrinite reflectance in sam-ples from the core, and bottomhole temperature in the well. The earliest fractures (group 1) likely formed due to early fluid-expulsion events (ca. 300 Ma) and were folded during host-rock compaction. Later group 2 fractures are sealed with fibrous barite containing primary, liquid hydrocarbon inclusions (mean homogenization temperature [Th] =-9 degrees C) and aqueous fluid inclusions (mean Th = 108.1 degrees C). Group 2 fractures likely formed in response to fluid overpressure associated with crack-ing of type II kerogen to oil. Group 3 vertical fractures are up to 2 m in height with kinematic apertures ranging from less than 0.05 to 1.4 mm, partly open, and strike dominantly 010 degrees-020 degrees. Sequentially trapped aqueous fluid inclusions in fracture-spanning quartz cement bridges (mean Th = 110 degrees C in crack-seal texture and 128 degrees C in post-crack-seal fracture cement) record fracture opening under increasing temperature, inferred to reflect increas-ing burial, with continued overpressuring during the Triassic to Late Cretaceous. Some group 3 fractures may have continued to fill during Cenozoic uplift.

Hydrogen (H2) is an attractive energy carrier to move, store, and deliver energy in a form that can be easily used. Field proven technology for underground hydrogen storage (UHS) is essential for a successful hydrogen economy. Options for this are manmade caverns, salt domes/caverns, saline aquifers, and depleted oil/gas fields, where large quantities of gaseous hydrogen have been stored in caverns for many years. The key requirements intrinsic of a porous rock formation for seasonal storage of hydrogen are: adequate capacity, ability to contain H2, capability to inject/extract high volumes of H2, and a reliable caprock to prevent leakage. We have carefully evaluated a commercial non-isothermal compositional gas reservoir simulator and its suitability for hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs. We have successfully calibrated the gas equation of state model against published laboratory H2 density and viscosity data as a function of pressure and temperature. Comparisons between the H2, natural gas and CO2 storage in real field models were also performed. Our numerical models demonstrated more lateral spread of the H2 when compared to CO2 and natural gas with a need for special containment in H2 projects. It was also observed that the experience with CO2 and natural gas storage cannot be simply replicated with H2.