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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 37 records · Page 2
All sourcesNASA NTRSDOE OSTI
DOE OSTI2015

A study of changes in deep fractured rock permeability due to coupled hydro-mechanical effects

This paper presents a numerical study of the hydro-mechanical behaviour of a fractured rock domain at 1000. m depth below the land surface as a function of different levels of fluid pore pressure. A 2D fractured rock domain is adopted based on data obtained from outcrop mapping, displaying multiple fracture sets, fracture intersections, dead-end and curved fractures. A continuum based numerical model is used to evaluate the effects of compressive boundary stresses, cracking by tension failure in the intact rock and fractures and shear displacement along fractures on its equivalent permeability. Two in situ stress boundary conditions are considered: an isotropic case SR1 with the two horizontal boundary compressive stresses having the same magnitude, and an anisotropic case SR2 with the ratio between these compressive stress components set to be 2. In the SR2 case, changes in the local stress and stress ratio distributions due to different fluid pore pressure levels are anisotropic and more significant than in the SR1 case, because of tension failures in the intact rock forming bridges between fractures. These failure regions opened new flow connections between fractures and thereby caused important anisotropic changes in the flow paths, and significant decrease in local gradients of fluid pore pressure. The equivalent permeability increases sharply when the fluid pore pressure is approximately 90% of the magnitude of the minimum stress at the boundaries of the fractured rock domain. Results show that the equivalent permeability of the fractured rock domain is most sensitive to the fractures normal stiffness, the permeability of the tension failure regions and the power-law exponent for permeability change.

58 GEOSCIENCES↗
DOE OSTI2024

Pore‐Scale Modeling of Reactive Transport with Coupled Mineral Dissolution and Precipitation

Abstract We present a new pore‐scale model for multicomponent advective‐diffusive transport with coupled mineral dissolution and precipitation. Both dissolution and precipitation are captured simultaneously by introducing a phase transformation vector field representing the direction and magnitude of the overall phase change. An effective viscosity model is adopted in simulating fluid flow during mineral dissolution‐precipitation that can accurately capture the velocity field without introducing any empirical parameters. The proposed approach is validated against analytical solutions and interface tracking simulations in simplified structures. After validation, the proposed approach is employed in modeling realistic rocks where mineral dissolution and precipitation are dominant at different locations. We have identified three regimes for mineral dissolution‐precipitation coupling: (a) compact dissolution‐precipitation where dissolution is dominant near the inlet and precipitation is dominant near the outlet, (b) wormhole dissolution with clustered precipitation where dissolution generates wormholes in the main flow paths and precipitation clogs the secondary flow paths, and (c) dissolution dominant where all solid grains are gradually dissolved. In the three regimes, the proposed approach provides reliable porosity‐permeability relationships that cannot be described well by traditional macroscale models. We find that the permeability can increase while the overall porosity decreases when the main flow paths are expanded by dissolution and adjacent pore spaces are clogged by precipitation.

58 GEOSCIENCES↗
DOE OSTI2014

Quantification of Wellbore Leakage Risk Using Non-destructive Borehole Logging Techniques

Well integrity is important at all potential CCS locations and may play a crucial role establishing leakage risk in areas where there is a high density of existing wells that could be impacted by the storage operations including depleted petroleum fields where EOR or CCS will occur. To address a need for risk quantification methods that can be directly applied to individual wells using borehole logging tools a study was conducted using data from five wells in Wyoming. The objectives of the study were: Objective 1: Develop methods to establish the baseline flow parameters (porosity and permeability or mobility) from individual measurements of the material properties and defects in a well. Objective 2: Develop a correlation between field flow-property data and cement logs that can be used to establish the flow-properties of well materials and well features using cement mapping tools. Objective 3: Establish a method that uses the flow-property model (Objective 2) to analyze the statistical uncertainties associated with individual well leakage that can provide basis for uncertainty in risk calculations. The project objectives were met through the logging of five wells in Carbon and Natrona County Wyoming to collect data that was used to estimate individual and average well flow properties and model the results using ultrasonic data collected during the logging. Three of the five wells provided data on point and average flow properties for well annuli. Data from the other two wells were used to create models of cement permeability and test whether information collected in one well could be used to characterize another well. The results of the in-situ point measurements were confirmed by the lab measurements sidewall cores collected near the same depths Objective 1 was met using the data collected through logging, testing, and sampling. The methods were developed that can establish baseline flow parameters of wells by both point and average test methods. The methods to estimate the flow properties modeling of point pressure tests, modeling of vertical interference tests, and laboratory measurement of cased-hole sidewall cores The wells were in sufficiently good shape to allow the development of the characterization methods while still having enough defects to study differences in results as they relate to well integrity. Samples and tests analyzed from three of five wells studied in showed the cements were largely intact and had not degraded from exposure native brines. Log results taken in conjunction with the core measurements indicate that interfaces and/or problems with cement placement due to eccentering provide preferential flow paths for fluids, which can increase the effective permeability of the barrier several orders of magnitude above the permeability of intact cement. The results of the maps created using logging tools indicating that the cement condition and bond are generally good identify a need for more research to understand how logs can be used to predicteffective well permeabilities such as those measured by the VITs in this study.

42 ENGINEERING↗
DOE OSTI2024

Mineral and fluid transformation of hydraulically fractured shale: case study of Caney Shale in Southern Oklahoma

This study explores the geochemical reactions that can cause permeability loss in hydraulically fractured reservoirs. The experiments involved the reaction of powdered-rock samples with produced brines in batch reactor system at temperature of 95 °C and atmospheric pressure for 7-days and 30-days respectively. Results show changes in mineralogy and chemistry of rock and fluid samples respectively, therefore confirming chemical reactions between the two during the experiments. The mineralogical changes of the rock included decreases of pyrite and feldspar content, whilst carbonate and illite content showed an initial stability and increase respectively before decreasing. Results from analyses of post-reaction fluids generally corroborate the results obtained from mineralogical analyses. Integrating the results obtained from both rocks and fluids reveal a complex trend of reactions between rock and fluid samples which is summarized as follows. Dissolution of pyrite by oxygenated fluid causes transient and localized acidity which triggers the dissolution of feldspar, carbonates, and other minerals susceptible to dissolution under acidic conditions. The dissolution of minerals releases high concentrations of ions, some of which subsequently precipitate secondary minerals. On the field scale, the formation of secondary minerals in the pores and flow paths of hydrocarbons can cause significant reduction in the permeability of the reservoir, which will culminate in rapid productivity decline. This study provides an understanding of the geochemical rock–fluid reactions that impact long term permeability of shale reservoirs.

58 GEOSCIENCES↗
DOE OSTI2026

Oil in Alaska North Slope Gas Hydrate Reservoir: Micro-CT and Flow Simulation Insights into Permeability

Gas hydrate-bearing sands on the Alaska North Slope (ANS) host minor volumes of crude oil whose impact on formation permeability has never been quantified relative to a gas hydrate reservoir system. Here, we combine in situ pressure-core microcomputed-tomography (μ-CT), thermogravimetric analysis (TGA), gas-chromatography–mass-spectrometry (GC–MS), scanning-electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), and Stokes-flow simulation to (i) quantify oil saturation, (ii) infer its source, and (iii) evaluate its influence on permeability after gas-hydrate dissociation. μ-CT and SEM-EDS imaging identify the host sediment as silty, with some grain-coating clay present. Eight representative 3003-voxel subvolumes extracted from a preserved pressure core (Core 15P-3c, from the B1 sand (unit B), HYDRATE 02 Geo Data Well (GDW), 886.96–887.29 m measured depth, MD) exhibit porosities of 0.34–0.37 and an average oil saturation of 0.09 ± 0.03, in comparison to an independent TGA-based estimate of 0.16. GC-MS fingerprints obtained from an adjacent depressurized core (Core 17P-1, 891.37–891.44 m MD), together with oil pore habit revealed by μ-CT, suggest that the oil is partly native but also includes contributions from mineral oil-based drilling fluid contamination. Further analysis of oil–porewater interactions and flushing tests confirms that native oil saturation in the analyzed samples ranges from 0.04 to 0.08 with an average of approximately 0.06, and the oil is highly immobile. Flow simulations demonstrate that the native oil saturation of ≈0.06 reduces permeability by approximately 50% due to both pore blockage and increased flow-path tortuosity. These findings reveal the potential presence of native oil within the ANS gas hydrate reservoir and suggest that future simulation models may need to account for its impact on permeability to improve long-term performance predictions of gas and water production.

02 PETROLEUM↗
DOE OSTI2020

Flow Channeling in Fracture Networks: Characterizing the Effect of Density on Preferential Flow Path Formation

Flow channelization is a commonly observed phenomenon in fractured subsurface media where the flow of fluids is restricted primarily to highly transmissive fracture networks surrounded by a low-permeability rock matrix. The multiscale structural heterogeneity of these networks results in multiscale flow channelization where preferential flow paths form at length scales ranging from the entire system down to the subfracture size. We present an analysis of how one of the largest scales in fractured media, the network density, influences the degree of flow channeling that occurs using an ensemble of semigeneric three-dimensional discrete fracture network (DFN) simulations. We construct 10 DFNs, whose fracture lengths follow a power law distribution, at four densities for a total of 40 networks. We characterize their structure in terms of the network topology and geometry. Eulerian and Lagrangian observations of the steady-state flow fields obtained within the networks are used to quantify the degree of flow channelization at the network scale. We introduce a measure for the importance-ranking/hierarchy of different flow paths in the network using graph-based analysis of Lagrangian transport by which the degree of flow channeling between networks is compared. These flow observations are then linked to the structural properties of the networks. In general, network-scale flow channeling decreases as the network density increases. However, at low densities, there is more uniform flow within the entire connected network than in high-density networks. We also demonstrate how standard transport observables can be used to infer the degree of flow channelization occurring within a fracture network.

58 GEOSCIENCES↗
DOE OSTI2017

Three‐Phase CO 2 Flow in a Basalt Fracture Network

Abstract Geologic CO 2 sequestration in basalt reservoirs is predicated on permanent CO 2 isolation via rapid mineralization reactions. This process is supported by a substantial body of evidence, including laboratory experiments documenting rapid mineralization rates, regional storage estimates indicating large, accessible storage reservoirs, and two successful pilot‐scale studies. Nevertheless, there remains significant uncertainty in the behavior of CO 2 flow within basalt fracture networks, particularly in the context estimating physical trapping potential in early time and as CO 2 undergoes phase change. In this study, a Monte Carlo numerical model is designed to simulate a supercritical CO 2 plume infiltrating a low‐permeability flood basalt entablature. The fracture network model is based on outcrop‐scale LiDAR mapping of Columbia River Basalt, and CO 2 flow is simulated within fifty equally probable realizations of the fracture network. The spatial distribution of fracture permeability for each realization is randomly drawn from a basalt aperture distribution, and ensemble results are analyzed with e‐type estimates to compute mean and standard deviation of fluid pressure and CO 2 saturation. Results of this model after 10 years of simulation suggest that (1) CO 2 flow converges on a single dominant flow path, (2) CO 2 accumulates at fracture intersections, and (3) variability in permeability can account for a 1.6 m depth interval within which free CO 2 may change phase from supercritical fluid to subcritical liquid or gas. In the context of CO 2 sequestration in basalt, these results suggest that physical CO 2 trapping may be substantially enhanced as carbonate minerals precipitate within the basalt fracture network.

Gierzynski, Alec O.↗
DOE OSTI2024

Relative permeabilities for two-phase flow through wellbore cement fractures

Multiple fluids are likely to exist in fractures and flow paths associated with leaky wellbores, including liquids (e.g., crude oil) and gases (e.g., gas exsolved from liquid). These fluids occupy and move through different portions of the pore spaces within the fractures depending on many factors, including fluid properties, fracture size, and the amount of the different fluids. Upward leakage of any phase, through the fracture, can contaminate water-bearing formations, create hazardous surface conditions, and compromise the functionality of the wellbore. Early signs of wellbore leaks may be expressed by anomalous pressure behavior at surface monitoring points on cavern storage wells. These pressure anomalies are difficult to interpret, necessitating knowledge of the factors that affect the multiphase flow in fractures and porous media. These parameters are critical to modeling multiphase flow in fractures. This insight can guide further diagnosis and maximize leak remediation. Here, our study focuses on the relationship of the liquid–gas relative permeabilities for representative variable-aperture wellbore cement fracture. To obtain the relative permeability of each phase, two-phase flow tests were conducted where both fluids were flowing simultaneously through a fractured wellbore cement specimen under a range of factors, namely (1) aperture size, (2) capillary numbers, and (3) viscosity ratio. The flow experiments were conducted under a range of confining stresses and flow velocities, using nitrogen gas and silicone oils (of different viscosities) in a specially designed pressure vessel. The sum of gas and oil relative permeabilities were found to be less than one under all conditions, which indicates that the presence of one phase affects the permeability of the other phase, and vice versa. Since the gas phase flow conditions include a significant inertial flow component in addition to viscous flow, the inertial flow coefficients at different saturation states are presented. The factors affecting the relationship between the relative permeabilities are discussed in detail. A new mathematical model for estimating the relative permeability of wellbore cement fracture is presented and experimentally validated.

58 GEOSCIENCES↗
DOE OSTI2017

Sodium Pumping via Condensation within a Non-Wetting Porous Structure

The sodium thermal electrochemical converter (Na-TEC) is a heat engine that generates electricity via the isothermal expansion of sodium ions through a beta”-alumina solid-electrolyte. The transfer of liquid sodium from a low-pressure condenser to a high-pressure evaporator is necessary to complete the thermodynamic cycle for this conversion process. A unique sodium capillary pump for the Na-TEC is proposed, whereby low-pressure sodium vapor is condensed within a non-wetting (i.e. contact angle > 90o) stainless steel porous structure. Due to the curvature of the non-wetting liquid-vapor interface, the liquid adjacent to the interface is at a higher pressure than the vapor. This is in contrast to traditional wicks, where the liquid adjacent to the interface has a lower pressure. Thus, the curvature created at this non-wetting condensation interface supplies a directed force upon the liquid sodium that effectively “pushes” it towards a high pressure region, whereas a traditional capillary wick “pulls” the liquid. Porous structures made of stainless steel 316 are commercially available, and this material is non-wetting to sodium at the relevant temperature range of the Na-TEC condenser (500K – 673K). An experimental set-up is used to measure several interfacial and transport properties of the condensed sodium within this porous structure. These properties include the temperature dependent Laplace pressure generated at the phase change interface and the permeability of the porous structure. Liquid sodium is in contact with the porous structure and is progressively pressurized with argon gas until the sodium “breaks through” and the liquid begins to flow. This break-through pressure is determined when electrical contact is established between the flowing liquid metal and a set of electrodes cemented along the flow path. The velocity of the flowing sodium can also be measured with these electrodes, and the permeability is then determined by fitting velocity data to the classical Darcy law. These interfacial properties are then applied to a conjugate heat transfer model, which treats the coupled momentum and thermal transport processes within the non-wetting porous structure as sodium vapor is condensed. Due to the low mass flowrates in the Na-TEC (< 0.1 mg/s), higher order friction terms are neglected and the classical Darcy’s law is used for non-isothermal, compressible sodium vapor flow. At lower temperatures, the sodium vapor density becomes sufficiently small and there is a transition from classic Poiseuille flow (Kn < 0.1) to Knudsen flow (Kn > 10). Furthermore, transport due to binary diffusion is considered for situations where there is a substantial presence of non-condensable argon inside the sodium vapor plenum. Initial modeling results showing expected mass flowrates, temperature profiles, and liquid-vapor interface locations are presented for various physical conditions. Finally, the main design features of an experimental set-up used to demonstrate this capillary pumping is described in detail, including the method used to measure the low sodium mass flowrates. Initial experimental results demonstrating sodium pumping for a range of temperatures (800K – 1100K) will be presented and compared against the model predictions. A pump curve used to gauge the performance of this pumping mechanism is also created.

14 SOLAR ENERGY↗
DOE OSTI2018

Interfacial and Transport Property Measurements of Liquid Sodium within a Porous Structure

The sodium thermal electrochemical converter (Na-TEC) is a heat engine that generates electricity via the isothermal expansion of sodium ions through a beta”-alumina solid-electrolyte. The transfer of liquid sodium from a low-pressure condenser to a high-pressure evaporator is necessary to complete the thermodynamic cycle for this conversion process. A unique sodium capillary pump for the Na-TEC is proposed, whereby low-pressure sodium vapor is condensed within a non-wetting (i.e. contact angle > π/2) porous sample. The curvature created at this non-wetting condensation interface supplies a directed force upon the liquid sodium that effectively “pushes” it towards a high pressure region, rather than a traditional capillary wick that “pulls” the liquid. Porous structures made of stainless steel 316 are commercially available, and this material is non-wetting to sodium at the relevant temperature range of the Na-TEC condenser (500K – 673K). An experimental set-up is used to measure several interfacial and transport properties of the condensed sodium within this porous structure. These properties include the temperature dependent Laplace pressure generated at the phase change interface and the permeability of the porous structure. For the former, liquid sodium is in contact with the porous structure and is progressively pressurized with argon gas in increments of ~ 5 kPa until the sodium “breaks through” and the liquid begins to flow. This breakthrough pressure is determined when electrical contact is established between the flowing liquid metal and a set of electrodes cemented into the flow path. The velocity of the flowing sodium can also be measured with these electrodes, and the permeability is then determined by fitting velocity data to the classical Darcy law. Statistically significant results of these measurements, taken at multiple sodium temperatures, are presented. Furthermore, contact angle measurements of sessile sodium drops on stainless steel 316 are demonstrated. This contact angle information is used to define an effective pore radius for the porous structure, which is then validated with microscopy. All the physical parameters described herein are used as inputs in a condensation model to predict the mass flowrate of condensing sodium under a given pressure gradient across the porous structure. This condensation model is used to design the capillary pump for the Na-TEC.

14 SOLAR ENERGY↗
DOE OSTI2023

Effective permeability of an immiscible fluid in porous media determined from its geometric state

Based on the phenomenological extension of Darcy's law, two-fluid flow is dependent on a relative permeability function of saturation only that is process or path dependent with an underlying dependency on pore structure and wettability. For applications (fuel cells to underground CO 2 storage), it is imperative to determine the effective phase permeability relationships where the traditional approach is based on the inverse modeling of time-consuming experiments. The underlying reason is that the fundamental upscaling step from pore to Darcy scale, which links the pore structure of the porous medium to the continuum hydraulic conductivities, is not solved. Herein, we develop an artificial neural network (ANN) that relies on fundamental geometrical relationships to determine the mechanical energy dissipation during creeping immiscible two-fluid flow. Finally, the developed ANN is based on a prescribed set of state variables based on physical insights that predict the effective permeability of 4500 unseen pore-scale geometrical states with R 2 = 0.98.

42 ENGINEERING↗
DOE OSTI2019

Numerical Evaluation of Unsaturated-Zone Flow and Transport Pathways at Rainier Mesa, Nevada

Sixty-one underground nuclear tests were conducted at Rainier Mesa at the Nevada National Security Site between 1957 and 1992. The mesa includes the highest-elevation areas at the Nevada National Security Site and experiences some of the highest estimated infiltration rates. Perched water is ubiquitous in many of the tunnels used for testing. The presence of sloping layers with strongly varying degrees of fracturing and overall permeability suggests that some infiltrating water may be diverted laterally along higher-permeability layers, thereby reducing overall percolation flux and radionuclide transport through the low-permeability testing horizons but also potentially transporting radionuclides laterally away from the test locations. A high-resolution, two-dimensional, cross-sectional model was created to simulate water and particle movement along potential lateral flow paths and to investigate flow and transport paths within and surrounding the perched water bodies. The model results indicate that particles with starting locations within the low-permeability perching layers will follow dominantly vertical trajectories through the perching horizons and reach the water table in the underlying carbonate aquifer only after many thousands of years. In contrast, particles starting near ground surface above the testing horizon are mostly diverted laterally before reaching the testing horizon, except where nearby faults through the perching layers are present. Where the rock above the perching horizon is fractured, particles originating near ground surface can move laterally with relatively high transport velocities. Transport calculations for 3 H show that transport extent is limited by slow matrix flow, radioactive decay, and matrix diffusion in the fractured units.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2016

Simulation of Hydraulic and Natural Fracture Interaction Using a Coupled DFN-DEM Model

The presence of natural fractures will usually result in a complex fracture network due to the interactions between hydraulic and natural fracture. The reactivation of natural fractures can generally provide additional flow paths from formation to wellbore which play a crucial role in improving the hydrocarbon recovery in these ultra-low permeability reservoir. Thus, accurate description of the geometry of discrete fractures and bedding is highly desired for accurate flow and production predictions. Compared to conventional continuum models that implicitly represent the discrete feature, Discrete Fracture Network (DFN) models could realistically model the connectivity of discontinuities at both reservoir scale and well scale. In this work, a new hybrid numerical model that couples Discrete Fracture Network (DFN) and Dual-Lattice Discrete Element Method (DL-DEM) is proposed to investigate the interaction between hydraulic fracture and natural fractures. Based on the proposed model, the effects of natural fracture orientation, density and injection properties on hydraulic-natural fractures interaction are investigated.

Discrete Fracture Network↗
DOE OSTI2013

Modeling of fault reactivation and induced seismicity during hydraulic fracturing of shale-gas reservoirs

We have conducted numerical simulation studies to assess the potential for injection-induced fault reactivation and notable seismic events associated with shale-gas hydraulic fracturing operations. The modeling is generally tuned towards conditions usually encountered in the Marcellus shale play in the Northeastern US at an approximate depth of 1500 m (~;;4,500 feet). Our modeling simulations indicate that when faults are present, micro-seismic events are possible, the magnitude of which is somewhat larger than the one associated with micro-seismic events originating from regular hydraulic fracturing because of the larger surface area that is available for rupture. The results of our simulations indicated fault rupture lengths of about 10 to 20 m, which, in rare cases can extend to over 100 m, depending on the fault permeability, the in situ stress field, and the fault strength properties. In addition to a single event rupture length of 10 to 20 m, repeated events and aseismic slip amounted to a total rupture length of 50 m, along with a shear offset displacement of less than 0.01 m. This indicates that the possibility of hydraulically induced fractures at great depth (thousands of meters) causing activation of faults and creation of a new flow path that can reach shallow groundwater resources (or even the surface) is remote. The expected low permeability of faults in producible shale is clearly a limiting factor for the possible rupture length and seismic magnitude. In fact, for a fault that is initially nearly-impermeable, the only possibility of larger fault slip event would be opening by hydraulic fracturing; this would allow pressure to penetrate the matrix along the fault and to reduce the frictional strength over a sufficiently large fault surface patch. However, our simulation results show that if the fault is initially impermeable, hydraulic fracturing along the fault results in numerous small micro-seismic events along with the propagation, effectively preventing larger events from occurring. Nevertheless, care should be taken with continuous monitoring of induced seismicity during the entire injection process to detect any runaway fracturing along faults.

03 NATURAL GAS↗
DOE OSTI2024

Design of a Meso-Scale Test of a Fracture Thermal Energy Storage (FTES) System

This paper will present the characterization, scaling, and design of an intermediate-scale field test of a fracture thermal energy storage system (FTES). Seasonal storage of thermal energy has the potential to both significantly reduce the total energy requirements for heating and cooling of buildings, but also allow for the flexibility to store thermal energy from intermittent sources. With approximately half of global energy consumption currently being used for heating and cooling, this represents an important path to reducing greenhouse gas (GHG) emissions. The concept of FTES is to drill two or more wells into a low permeability formation, generally at a depth of less than a few hundred meters, and then generate hydraulic fractures to create flow paths for water to circulate between the wells. Hot or cold thermal energy can then be stored in the surrounding rock mass by circulating hot or cold water through the fractures, which will heat or cool the rock mass. To recover the stored energy, ambient temperature water can be then circulated through the fractures, which will then be heated or cooled by the rock mass. Fractures inherently have a very large ratio of surface area to volume. This allows for very high heat fluxes to and from the rock mass to be achieved despite the relatively low thermal conductivity of most geologic formations. Because large fractures can be made with low-cost equipment and with only inexpensive and environmentally safe materials such as water and sand, the cost to construct even large FTES systems is expected to be quite low. This paper will present what the performance requirements, size, and operating conditions of a full-scale system to operate a commercial building. The paper will describe how these full-scale system characteristics will be used as a design basis for an intermediate-scale FTES test to be conducted at the Sanford Underground Research Facility (SURF) in Lead, SD.

Burghardt, Jeffrey A.↗
DOE OSTI2013

Geomechanical effects on CO 2 leakage through fault zones during large-scale underground injection

The importance of geomechanics—including the potential for faults to reactivate during large-scale geologic carbon sequestration operations—has recently become more widely recognized. However, notwithstanding the potential for triggering notable (felt) seismic events, the potential for buoyancy-driven CO 2 to reach potable groundwater and the ground surface is actually more important from public safety and storage-efficiency perspectives. In this context, this paper extends the previous studies on the geomechanical modeling of fault responses during underground carbon dioxide injection, focusing on the short-term integrity of the sealing caprock, and hence on the potential for leakage of either brine or CO 2 to reach the shallow groundwater aquifers during active injection. We consider stress/strain-dependent permeability and study the leakage through the fault zone as its permeability changes during a reactivation, also causing seismicity. We analyze several scenarios related to the volume of CO 2 injected (and hence as a function of the overpressure), involving both minor and major faults, and analyze the profile risks of leakage for different stress/strain-permeability coupling functions. We conclude that whereas it is very difficult to predict how much fault permeability could change upon reactivation, this process can have a significant impact on the leakage rate. Moreover, our analysis shows that induced seismicity associated with fault reactivation may not necessarily open up a new flow path for leakage. Results show a poor correlation between magnitude and amount of fluid leakage, meaning that a single event is generally not enough to substantially change the permeability along the entire fault length. Finally, and consequently, even if some changes in permeability occur, this does not mean that the CO 2 will migrate up along the entire fault, breaking through the caprock to enter the overlying aquifer.

54 ENVIRONMENTAL SCIENCES↗