Mineral carbon storage in basalt has been proven as an effective means of durable and verifiable geologic carbon sequestration. This study investigates a novel technology aimed at optimizing subsurface mineralization: water-alternating-gas (WAG), or cycled injections of free-phase CO2 (e.g., supercritical) and water. Incorporating injection of supercritical CO2 (scCO2) into basalt can minimize water demand, increase per-well injection capacity, and expand the feasible range of basalt carbon storage. Cycling water between injection of scCO2 can accelerate geochemical reactions and shorten mineralization timeframes. We model aqueous-phase, scCO2-only, and WAG injections into subsea and onshore basalt sites using the STOMP-CO2 simulator. We first simulate WAG injection into mid-ocean ridge basalt at the Juan de Fuca plate in the Northeast Pacific Ocean to investigate injection parameters and reservoir characteristics that accelerate mineralization during WAG injections. Results indicate that WAG injections can be optimized to mineralize 100 % of a 1 Mt CO2 injection within 40 years. Optimized WAG injections can double mineralization compared to traditional scCO2-only using half as much water as an aqueous-phase approach. We then compare the efficiency of WAG injections by simulating scenarios at two additional sites: offshore basalt in the Louisville Seamount, a subocean volcano in the Southwest Pacific, and continental flood basalt along the Columbia River in Washington State. We observe faster mineralization at the Louisville seamount than the Juan de Fuca site, likely due to variations in injection-zone mineralogy. At the Columbia River site, WAG scenarios improve mineralization the most relative to the scCO2-only injection and increase feasible per-well injection rates relative to aqueous-phase approaches. Our results indicate that WAG has the potential to optimize carbon mineralization in basalt and substantially advance the scalability of this technology.

A series of six aqueous-soluble and four nonaqueous-soluble tracer experiments and corresponding numerical simulations were executed for the Farnsworth Field in Ochiltree County, Texas, USA, a field which is undergoing tertiary enhanced oil recovery with water-alternating-gas (WAG) production. The combination of field experiments and numerical simulations was designed to identify flow pathways between injectors and producers and potential short circuiting of injected fluids. Field recoveries of aqueous-soluble tracers were dependent on the WAG stages of the tracer injection well, with shorter arrival times for strictly waterflooding and delayed arrival times for alternating injection stages. Aqueous-soluble tracer (i.e., 1,3,6-naphthalene trisulfonate, 1,5-naphthalene disulfonate, 1,6-naphthalene disulfonate, 2-naphthalene sulfonate, 2,6-naphthalene disulfonate, and 2,7-naphthalene disulfonate) arrivals for WAG injectors indicated water bypass was occurring during gas injection stages. Nonaqueous-soluble tracer (i.e., perfluoro-1,2-dimethylcyclohexane, perfluoroethylcyclohexane, perfluoromethylcyclohexane, and perfluoromethylcyclopentane) experiments revealed faster migration velocities than for the aqueous-soluble tracers and flow heterogeneities that resulted in the tracers bypassing nearer production wells. Base-case numerical simulations of the tracer experiments used a geologic model of the Morrow B sandstone production interval with parameters calibrated from history matching simulations, with the Morrow B sandstone sub-divided into hydrologic flow units (HFUs). Alternative simulation scenarios investigated HFU-dependent three-phase relative permeability models and dynamic intrinsic permeability enhancement with exposure to aqueous-dissolved CO2. Compositional petroleum models with four components were shown to be sufficient for tracer modeling compared against a nine-component model, with a factor of four difference in simulation execution time. HFU-dependent relative permeability models and dynamic intrinsic permeability modifications influenced arrival times and production concentrations of both aqueous- and nonaqueous-soluble tracers but did not yield unique flow pathways compared to those observed in the base-case scenario.

With the goal of better understanding stimulation in crystalline rock for improving enhanced geothermal systems (EGS), the EGS Collab Project performed a series of stimulations and flow tests at 1.25 and 1.5 km depths. The tests were performed in two well-instrumented testbeds in the Sanford Underground Research Facility in Lead, South Dakota, United States. The testbed for Experiment 1 at 1.5 km depth contained two open wells for injection and production and six instrumented monitoring wells surrounding the targeted stimulation zone. Four multistep stimulation tests targeting hydraulic fracturing and nearly year-long ambient temperature and chilled water flow tests were performed in Experiment 1. The testbed for Experiments 2 and 3 was at 1.25 km depth and contained five open wells in an outwardly fanning five-spot pattern and two fans of well-instrumented monitoring wells surrounding the targeted stimulation zone. Experiment 2 targeted shear stimulation, and Experiment 3 targeted low-flow, high-flow, and oscillating pressure stimulation strategies. Hydraulic fracturing was successful in Experiments 1 and 3 in generating a connected system wherein injected water could be collected. However, the resulting flow was distributed dynamically, and not entirely collected at the anticipated production well. Thermal breakthrough was not observed in the production well, but that could have been masked by the Joule-Thomson effect. Shear stimulation in Experiment 2 did not occur - despite attempting to pressurize the fractures most likely to shear - because of the inability to inject water into a mostly-healed fracture, and the low shear-to-normal stress ratio. The EGS Collab experiments are described to provide a background for lessons learned on topics including induced seismicity, the correlation between seismicity and permeability, distributed and dynamic flow systems, thermoelastic and pressure effects, shear stimulation, local geology, thermal breakthrough, monitoring stimulation, grouting boreholes, modeling, and system management.

Closed-loop geothermal systems (CLGSs) rely on circulation of a heat transfer fluid in a closed-loop design without penetrating the reservoir to extract subsurface heat and bring it to the surface. We developed and applied numerical models to study u-shaped and coaxial CLGSs in hot-dry-rock over a more comprehensive parameter space than has been studied before, including water and supercritical CO2 (sCO(2)) as working fluids. An economic analysis of each realization was performed to evaluate the levelized cost of heat (LCOH) for direct heating application and levelized cost of electricity (LCOE) for electrical power generation. The results of the parameter study, composed of 2.5 million simulations, combined with a plant and economic model comprise the backbone of a publicly accessible web application that can be used to query, analyze, and plot outlet states, thermal and mechanical power output, and LCOH/LCOE, thereby facilitating feasibility studies led by potential developers, geothermal scientists, or the general public (https://gdr.openei.org/submissions/1473). Our results indicate competitive LCOH can be achieved; however, competitive LCOE cannot be achieved without significant reductions in drilling costs. We also present a site-based case study for multi-lateral systems and discuss how our comprehensive single-lateral analyses can be applied to approximate multi-lateral CLGSs. Looking beyond hot-dry-rock, we detail CLGS studies in permeable wet rock, albeit for a more limited parameter space, indicating that reservoir permeability of greater than 250 mD is necessary to significantly improve CLGS power production, and that reservoir temperatures greater than 200 degrees C, achieved by going to greater depths (similar to 3-4 km), may significantly enhance power production.

The objective of this study was to investigate the transport and fate of CO2 injected into a sandstone reservoir in the western Farnsworth Unit, a hydrocarbon field in northern Texas. The study employed three-dimensional multifluid-phase numerical reactive solute and heat transport modeling. Model inputs were obtained from previous field characterization studies and calibrated to 8 years of historical production data. The CO2 in the models was injected through multiple wells for the first 25 years of the simulations according to a water-alternating gas schedule. The simulations were carried out for a total of 1000 years in order to study the long-term effects of CO2 injection.The results show that the largest fraction of the injected CO2 is stored in oil, followed by successively smaller amounts in the formation water, carbonate mineral phases, and as an immiscible gas phase. The small fraction of CO2 present as an immiscible gas, the most mobile phase for CO2, aids in the long-term sequestration security of the injected CO2. The injected CO2 was found to migrate within a maximum radius of around 500 m of the injection wells. This means that changes in fluid pressure, temperature, composition, and reservoir mineralogy were also limited to occurring within this radius. This radius is very sensitive to model relative permeability and capillary pressure values, which were determined from history matching to the field production data. The models predicted dolomite to be the main mineral sink for the injected CO2. Quartz was another mineral predicted to precipitate, whereas calcite, albite, chlorite, illite, and kaolinite were predicted to dissolve. The changes in mineral abundance had minimal effect on porosity, implying that the permeability of the reservoir should also not change much because of CO2 injection. (c) 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

The EGS Collab project, supported by the US Department of Energy, is performing intensively monitored rock stimulation and flow tests at the 10-m scale in an underground research laboratory to address challenges in implementing enhanced geothermal systems (EGS). Data and observations from the field tests are compared to simulations to understand processes and build confidence in numerical modeling of the processes. Experiment 1 examined hydraulic fracturing in a well-characterized fractured phyllite 1.5 km deep at the Sanford Underground Research Facility (SURF). Testbed characterization included fracture mapping, borehole acoustic and optical televiewers, full waveform sonic, conductivity, resistivity, temperature, campaign p- and s-wave investigations and electrical resistance tomography. Borehole geophysical techniques including passive seismic, continuous active source seismic monitoring, electrical resistance tomography, fiber-based distributed strain, distributed temperature, and distributed acoustic monitoring, were used to carefully monitor stimulation events and flow tests. More than a dozen stimulations and nearly one year of flow tests were performed. Quality data and detailed observations were collected and analyzed during stimulation and water flow tests, and these data are available. We achieved adaptive control of the tests using real-time monitoring and rapid dissemination of data and near-real-time simulation. Experiment 2 examines the potential for hydraulic shearing in amphibolite 1.25 km deep at SURF. The testbed consists of nine subhorizontal boreholes, four of which surround the testbed with grouted-in ERT, seismic sensors, CASSM and distributed fiber sensors. The test wells include a “five-spot” set with an injection well and four production/monitoring wells. Like Experiment 1, the testbed was characterized geophysically and hydrologically, and three stimulations have been performed using new tools.

Carbon storage in basalt offers secure, long-term CO2 storage due to the potential for mineralization. This method involves in-situ injections of carbon into basaltic formations, where carbon is sequestered in an aqueous phase through dissolution, and subsequently in mineral form through silicate chemical weathering and carbonate precipitation reactions. Mineralization of carbon in basaltic reservoirs has been demonstrated to be both rapid and effective during two field-scale pilot experiments. Some constraints to scaling the current technology for climate-relevant impact arise from the water-intensive injection method and the limited availability of continental basalt formations. Development of carbon storage in offshore basalt has the potential to circumvent these limitations due to the large reservoirs of both seawater and subseafloor basalt; however, high offshore drilling costs require the development of strategies that maximize per-well CO2 storage capacity. Here we investigate alternating injections of pure-phase supercritical CO2 with seawater, referred to as Water-Alternating-Gas (WAG) injections. We use the STOMP-CO2 simulator to model million-ton scale injections of CO2 into subsea basalt, testing various WAG scenarios designed to optimize mineralization. Results show that WAG scenarios can result in the mineralization of up to ~91% of injected CO2 within 20 years. By maximizing both per-well injection capacity and mineralization efficiency, Water-Alternating-Gas methods have the potential to advance and scale this proven carbon storage technology.

Despite the wide application of hydraulic fracturing in enhanced geothermal system (EGS) development and unconventional hydrocarbon production, our understanding of the many factors affecting the propagation of hydraulic fractures has relied on circumstantial evidence. This is partly due to the scarcity of direct observations in the subsurface. The EGS Collab project attempts to address these issues in the context of EGS research by performing intermediate‐scale (∼10 m) hydraulic stimulation experiments in a thoroughly characterized and heavily instrumented underground testbed. This paper analyzes the data collected from the first suite of hydraulic fracturing tests in this testbed, consisting of seven stimulation episodes. High‐quality microseismic data delineate five planar features very clearly. Combining fracture‐wellbore intersection observations from distributed temperature sensing (DTS) and visual observations from an open‐hole well, as well as prior in‐situ stress measurements, we conclude with high certainty that the four larger planes were hydraulic fractures. The growth of the hydraulic fractures was temporarily halted by a prominent, open natural fracture in the testbed but they eventually crossed and slightly reoriented under continued stimulation. Mineral‐filled (i.e., healed) natural fractures, though prevalent in the testbed, did not have perceivable effects on hydraulic fracture propagation. The high‐quality, mutually corroborating data sets allowed conclusions to be drawn with high confidence and attests to the advantage of intermediate‐scale experiments in subsurface research.

The objectives of this study were (1) to assess the fate and impact of CO2 injected into the Morrow B Sandstone in the Farnsworth Unit (FWU) through numerical non-isothermal reactive transport modeling, and (2) to compare the performance of three major reactive solute transport simulators, TOUGHREACT, STOMP-EOR, and GEM, under the same input conditions. The models were based on a quarter of a five-spot well pattern where CO2 was injected on a water-alternating-gas schedule for the first 25 years of the 1000 year simulation. The reservoir pore fluid consisted of water with or without petroleum. The results of the models have numerous broad similarities, such as the pattern of reservoir cooling caused by the injected fluids, a large initial pH drop followed by gradual pH neutralization, the long-term persistence of an immiscible CO2 gas phase, the continuous dissolution of calcite, very small decreases in porosity, and the increasing importance over time of carbonate mineral CO2 sequestration. The models differed in their predicted fluid pressure evolutions; amounts of mineral precipitation and dissolution; and distribution of CO2 among immiscible gas, petroleum, formation water, and carbonate minerals. The results of the study show the usefulness of numerical simulations in identifying broad patterns of behavior associated with CO2 injection, but also point to significant uncertainties in the numerical values of many model output parameters.

Fluid flow through fractured rock systems is governed in large part by the distribution, interconnectivity, and size of fracture apertures. In‐situ stress is one of the primary factors controlling fracture aperture, and one that is altered significantly during high‐pressure fluid injections or extractions. Interactions between stress, pore pressure, aperture, and fluid flow can result in complex and evolving poroelastic behavior with significant implications regarding the predictability and risk involved with developing and managing deep subsurface reservoirs (geothermal, fossil energy, and geologic carbon sequestration). In saturated rocks, bulk electrical conductivity is sensitive to both primary and secondary porosity (i.e., matrix porosity and fractures), and therefore to fracture aperture size and distribution. We demonstrate the use of time‐lapse 3D electrical resistivity tomography for remotely monitoring stress induced changes in aperture distribution during high pressure injections into a dense fractured rock system at a scale of tens of meters. Results reveal a complex and continuously evolving stress field involving aperture dilations in the natural fracture system and aperture contractions in adjacent zones of shadow stress. Results provide information about the spatiotemporal changes in the system behavior and point to the potential of electrical imaging for autonomously and remotely monitoring evolving stress conditions by proxy through changes in bulk electrical conductivity.

The development of Enhanced Geothermal Systems (EGS) requires an ability to accurately predict the flow rates and temperatures of the production wells. While simple in concept, EGS is complicated by the heterogeneity and complexity of fracture pathways that can lead to channeling, short-circuiting, and premature thermal breakthrough. The EGS Collab project will establish a suite of intermediate-scale (~10-20 m) field test beds coupled with stimulation and interwell flow tests that will provide a basis to better understand the fracture geometries and processes that control heat transfer between rock and stimulated fractures. As such, the EGS Collab experiments will provide a relatively inexpensive means of testing tools and concepts that could later be employed under geothermal reservoir conditions at FORGE. Our tests will be well-controlled, in situ experiments focused on rock fracture behavior and permeability enhancement. Pre- and post-test modeling of each test will allow for model prediction and validation. Comprehensive instrumentation will be used to collect high-quality and high-resolution geophysical and other fracture characterization and fluid flow data, and these data will be analyzed and compared with models and field observations to further elucidate the basic relationships between stress, induced seismicity, and permeability enhancement. To the maximum extent achievable, we will observe and quantify other key governing parameters that impact permeability, and attempt to understand how these parameters might change throughout the development and operation of an EGS project with the goal of enabling commercial viability of EGS. Evaluation of site criteria led the team to choose the Sanford Underground Research Facility (SURF) in South Dakota as the EGS Collab project experimental site. Our team is well underway with designing the first field experiment planned for this project, which is supported by the US Department of Energy’s Geothermal Technologies Office.

Understanding the time-dependent behavior of reservoir and sealing formations for geologic carbon storage is critical to assessing geomechanical risks since time-dependent deformation strongly influences the mechanical response of some rock types. Many studies have evaluated the risk of CO2 leakage and induced seismicity by assuming poroelastic rheology in sealing formations. Few have considered viscoelastic or other time-dependent responses, and much of the literature on the long-term mechanical behavior of rocks examines only a 1D uniaxial response. This is primarily because, to date, the general form of a reasonable 3D time-dependent model for rocks remains unclear. In this paper, we propose an approach to address this by using a new workflow to estimate constitutive modeling parameters for the evaluation of a 3D viscoelastic model. The proposed approach uses a 1D power-law response to extrapolate several-hour-long experimental data to the decades-long time frames of interest in geologic carbon storage. Experimental data were obtained by conducting multi-level loading/unloading triaxial relaxation tests with four different rock types. The experimental results showed that the maximum load relaxation observed is approximately 49%, with some rock types considered showing as little as 1.4%. Using the proposed workflow, two linear 3D viscoelastic models, i.e., generalized Maxwell (GM) model and fractional Kelvin-Voigt (FKV) model, were evaluated and their model parameters were chosen with the extrapolated 30year data such that a maximum deviation from the assumed power-law response for these two 3D models was 2 MPa in axial stress and 7 MPa in radial stress. We provided reasonable ranges for the model parameters to be later used for 3D modeling of rock time-dependent responses. Our results also showed that when GM is selected to analyze the rocks considered here, the relaxation time has a general range of 1-1010 s. This time scale captures the time-dependent behavior as long as centuries, which is much longer than a 10-30 years-long time frame envisioned for CO2 injection projects.

This paper investigates the consequences of time-dependent deformation on the stress changes and resulting geomechanical risks from injection of CO2 into geologic reservoirs. Using 3D fully coupled fluid flowgeomechanics simulations, it is shown that when time-dependent deformation occurs in the caprock, the shear stress decreases in the caprock but increases in the reservoir. The magnitude of this transfer of shear stress from caprock to reservoir is affected by the characteristic time scale of the time-dependent deformation of the adjacent formations. Compared to an elastic response, viscoelastic deformation of the caprock produces a higher possibility of fault failure within the reservoir during and after CO2 injection. The implication is that if the timedependent deformation of the caprock is neglected by assuming the purely elastic behavior of the caprock, the geomechanical risk will be underestimated.

Heat recovery from an enhanced geothermal system (EGS) is a complex process involving heat transport in both fracture networks and rock formations. A comprehensive understanding of and the ability to model the underlying heat transport mechanisms is important for the success of EGS commercialization but remains challenging in practice due to the generally insufficient characterization of EGS reservoirs. In the present study, we analyze an extensively monitored intermediate-scale EGS field experiment performed in a well-characterized testbed. The high-resolution, high-quality measurements from the field experiment enable the development of a high-fidelity model incorporating a well-constrained fracture network. Based on the field experiment, we investigate the complex heat transport processes in an EGS-relevant environment and validate the capability of a numerical approach in simulating these inherently coupled heat transport processes. A series of numerical simulations were performed to study the effects of different heat transport mechanisms, including thermal convection with fracture flow, thermal conduction in rock formations, and the Joule-Thomson effect. The agreement of thermal responses between field measurements and simulation results indicates that our numerical approach can appropriately model the heat transport processes pertaining to heat recovery from EGS reservoirs.