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DOE OSTI2020

Ammonia Permeation Through Inorganic Membranes

Moisture probes are used in the tritium facility to measure the moisture content of the gas stream. When tritium reacts with nitrogen to form ammonia, the ammonia gas damages the sensitive moisture probe. The gas stream tested during this experiment for moisture probe protection is composed of nitrogen and argon gas in conjunction with ammonia and water vapor. The gas stream is filtered through an inorganic membrane due to the high reactivity of tritium and a residual gas analyzer (RGA) is used to measure the ammonia and water vapor in the gas stream, as well as the permeability of nitrogen and argon through the inorganic membranes. The membranes tested were boron nitride and silver. The permeability was compared for each membrane at different pressures and flow rates. Fourier-transformed infrared spectroscopy (FT-IR) was used to compare the membranes before and after ammonia permeation. Ammonia gas is a byproduct formed from tritium gas reacting with nitrogen in the gas stream, similar to the Haber Process which occurs when hydrogen reacts with nitrogen [2]. The corrosive nature of ammonia damages metals and sensitive instruments such as moisture probes. Moisture probes are essential in various gas and liquid processes for measuring the moisture content of a gas. Membrane research has found that graphene oxide membranes successfully uptake ammonia from the gas stream at a humidity of approximately 30% at which point the pores pin closed, preventing gas permeation. Further research is being conducted to find an inorganic membrane that will prevent ammonia permeation thus circumventing damage to the sensitive moisture probe. The permeation measurements for argon and nitrogen gas and water and ammonia vapor were measured at various pressures of 800, 1000, 1200, 1500, 1800, and 2000 torr. The permeability average (PA) was calculated for each filter using a Barrer calculation. The average permeations for each filter were then compared. The gas composition was measured using the RGA Nitrogen was permeated through the membranes after ammonia permeation and a FT-IR spectrum was obtained. Boron Nitride: As the nitrogen pressure increased, the permeability of the membrane decreased from 800-1200 torr and remained relatively unchanged from 1200-2000 torr. The membrane exhibited a slight decrease in argon permeability from 800-1200 torr and a slight increase from 1500-2000 torr. The boron nitride membrane when permeated with ammonia and nitrogen prevented less ammonia permeation compared to the blank filter. The boron nitride filter demonstrated a decrease in permeability after ammonia permeation. Silver Membrane: When permeated with nitrogen alone, the membrane permeability decreased from 800 torr to 1200 torr. The permeability of the membrane showed little difference as pressure increased from 1200 torr. When permeated with argon, the same phenomenon occurred but on a much smaller scale. When compared to the blank and the boron nitride membranes the silver membrane exhibited significantly lower permeability. This may be in part due to the coating on the silver membrane and differences in pore size of the membranes. During permeation with ammonium hydroxide vapor and nitrogen, the partial pressure of the ammonia increased as compared to the blank membrane. The permeability before and after permeation with ammonia and nitrogen were compared. Permeability values suggested that after being permeated with the ammonia that the permeability for lower pressures increased slightly. There was no significant change in the FT-IR spectrums before and after permeation. Future work: Continue testing various inorganic membranes for ammonia permeation. Further research chemical separation of ammonia from the gas stream, which may prove difficult due to the high reactivity of tritium.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗

DOE OSTI2018

Quantitative Characterization of Impacts of Coupled Geomechanics and Flow on Safe and Permanent Geological Storage of CO 2 in Fractured Aquifers

This is the final scientific report for the award DE-FE0023305, entitled “Quantitative Characterization of Impacts of Coupled Geomechanics and Flow on Safe and Permanent Geological Storage of CO 2 in Fractured Aquifers.” The work has been divided into six tasks. In Task 2, we characterized rock properties, which are important when developing a quantitative approach for understanding and predicting geomechanical effects on large-scale CO 2 injection and long-term storage in the subsurface. Rock properties of interest for this characterization include porosity, permeability, elastic constants, strength, and heat capacity. We measured rock properties for three different rock types: concrete, sandstone and shale. These properties were obtained from the acoustic measurement, permeability and porosity measurement, Brazilian test, the uniaxial compressive test, and heat capacity measurement. Then, using the Brazilian technique to fracture samples, we measured their permeability under brine injection for varying effective stresses, followed by similar measurements of permeability under sc-CO 2 injection. Permeability to brine and sc-CO 2 decreased as the effective stress increased. The apparent permeability to sc-CO 2 was an order of magnitude less than that for brine, a consequence of CO 2 being the non-wetting fluid. In Task 3, we developed understandings and correlations for CO 2 injection pressure induced fracturing. We initially fractured four eight inch cubes of concrete with brine to establish a standard test procedure. Then, additional concrete samples were fractured using brine. Confining stresses were exerted on the samples and brine was injected at a constant rate into a borehole that was previously drilled into the concrete cube. The borehole pressure was measured and fracture initiation was identified as a peak in the pressure profile. That was followed by fracture propagation, which was identified as a plateau in the pressure profile, and finally the fracture reached the sample surface. The sample surfaces were photographed before and after fracturing, which enabled determination of where the fracture reached the sample surface. Afterwards, aqueous food dye solution was injected into the fractured concrete samples to color the fracture planes. The borehole was filled with food dye solution in advance, a gas pulse was transmitted to the borehole, and the borehole was then shut in to allow the food dye to be driven into existing fractures. Then, the concrete samples were broken down by high-pressure gas injection to reveal the geometry and morphology of the hydraulic fractures. In addition, acoustic measurements were conducted on multiple locations on each face of the concrete samples before and after injection for comparison. This comparison was used to confirm changes in the internal structure of the concrete sample, namely the formation of fractures. There were six concrete samples fractured with brine. Afterwards, concrete samples were fracture using sc-CO 2 . The main change in experimental procedure was the inclusion of temperature control, since in the field, we mostly encounter temperature and pressure conditions above the supercritical point of CO 2 . The concrete samples were pre-heated in an oven to elevate their temperature, and thermal tape was used to heat the CO 2 to a temperature above its supercritical temperature. Two concrete samples were fractured using liquid CO 2 , four concrete samples were fractured using gaseous CO 2 , and twenty two concrete samples were fractured using sc-CO 2 . For the concrete samples fractured using sc-CO 2 , three had pre-existing hydraulic fractures on the surface near the wellbore, and two were water saturated (as opposed to containing only air). Two concrete samples were composite samples, with a high permeability ball in the center, in order to represent CO 2 injection into a high permeability zone surrounded by a low permeability sealing formation. Later, we fractured five shale samples, obtained from the Niobrara shale outcrop, with sc-CO 2 . The injection rate was constant, confining stresses were applied, the shale samples were pre-heated in an oven to the desired temperature, and the sample was then fractured. An analysis of the failure type was done for many of the concrete samples, based on the predicted break down pressure for tensile and shear failure, and it was found that most samples fractured due to shear failure. Also, the presence of induced fractures has little to no effect on the fracture initiation pressure, but significantly changes the fracture morphology. The CO 2 fracturing in water saturated samples behaved much similar to brine induced fracturing. There was a significant difference of breakdown pressure for injection of CO 2 and brine, where the breakdown pressure for CO 2 induced fracturing is generally around the minimum horizontal stress and that for brine is much higher. Finally, the fracture orientation for most samples with large confining stress differential was perpendicular to the minimum horizontal stress. When the stress differential, especially the difference between the two directions with the smallest stresses was small, the fracture orientation was determined not only by the minimum stress direction, but also the magnitude of the confining stress, the tensile strength of the rock, and the breakdown pressure. In Task 4, we modified our coupled flow-geomechanical models to model fracture growth and propagation in storage formations and caprocks. These flow-geomechanical models are TOUGH2-CSM and TOUGH2-FLAC. The TOUGH2-CSM fluid and heat flow formulation is based on the TOUGH2 formulation of mass and energy conservation equations that govern fluid and heat flow in general multiphase, multicomponent, multi-porosity systems. The TOUGH2-CSM simplified geomechanical formulation is based on the linear theory of elasticity applied to multi-porosity non-isothermal (thermo-multi-poroelastic) media. We previously derived, from the fundamental relations of the linear theory of elasticity, an equation relating mean stress, pore pressures, temperatures, and body force (the Mean Stress equation) that we added to the TOUGH2-CSM fluid and heat flow equations. We extended the TOUGH2-CSM simplified geomechanical formulation to calculate the entire stress tensor by deriving equations for stress tensor components from derivatives of the Cartesian thermo-multi-poroelastic Navier equation components. In addition, we derived equations for stress tensor components in rz-coordinates. We solved these geomechanical equations using the integral finite difference method. This method utilizes momentum fluxes obtained by “factoring” a divergence operator out of each geomechanical equation. In Task 5, we did a literature survey to determine suitable correlations for fracture initiation, growth, and propagation. After surveying numerous papers, we modified TOUGH2-CSM to model stress dependent fracture initiation and growth using the Mohr-Coulomb criterion for shear failure in faults and caprock and the condition of negative minimum effective stress for tensile failure. Tensile failure results in a fracture whose width depends on the difference between fracture pressure and minimum stress and whose propagation is based on the difference between the stress intensity factor at the fracture tip and the rock toughness. The TOUGH-FLAC model is based on the FLAC3D ubiquitous joint model, extended for the modeling of permeability changes induced by changes in effective normal stress across fractures as well permeability changes caused by shearing along fractures. In Task 6, we validated our coupled flow-geomechanical models using analytical solutions and problems from the literature. We validated the TOUGH2-CSM modifications using analytical solutions to the displacement from a uniform load on a semi-infinite elastic medium and the two-dimensional Mandel-Cryer effect. Those were followed by a sample problem to test our stress tensor calculations, which was for injection into a single-phase reservoir with constant properties. Comparisons of our simulator to published results were done on for the depletion of a single-phase reservoir with stress dependent porosity, two examples from the In Salah gas project, an axisymmetric baserock–reservoir–caprock system with a normal faulting stress regime that had thermally induced shear stresses, simulations of CO 2 leakage through caprock in a two-dimensional reservoir in Cartesian coordinates, and predictions of caprock failure from CO 2 injection into an axisymmetric reservoir. Finally, we simulated CO 2 injection pressure-induced fracturing from one of our laboratory studies, Sample 39, and obtained a fracture profile. We also validated the TOUGH2-FLAC model for fluid driven fracture growth against solutions based on the KGD model and a case with an inclined fracture that was loaded from the boundaries to achieve wing-crack propagation. The strain softening tensile behavior and softening of modulus considering a simple damage approach was verified by a simulation representing hydraulic fracturing stress measurement around a vertical well. Finally, the model was validated against deep fracture zone opening and surface uplift at In Salah with inverses analysis used to improve the match of simulation with field data. In Task 7, we developed a scheme based on inverse modeling that can be used to identify caprock leakage. Injection of fluid into a reservoir results in a time varying pressure profile that depends on the properties of the rock and the fluid. The presence of significant caprock leakage would effect this pressure profile and we used inverse modeling, namely the Levenberg-Marquardt method, to determine the leakage location from the pressure profile. A two-dimensional and a three-dimensional example based on published data were presented. The published simulation was run and its results were considered as “field” data. In the two-dimensional example, a simulation of CO 2 injection into a two-dimensional aquifer-caprock system, the caprock had a vertical fault through which leakage could occur. The location of this leakage was obtained from our inverse modeling scheme. In the three-dimensional example, the simulation domain had four geological layers, one of which was the injection zone that contained a horizontal injection well. We simulated fractures as high permeability gridblocks, introduced a fracture that spanned the caprock depth, and ran a simulation to obtain “field” data. Then, using our inverse modeling scheme, we obtained the location of that fracture.

58 GEOSCIENCES↗

DOE OSTI2023

Using high pressure solutions of polyfluoroacrylate and CO 2 to Seal cement cracks for improved wellbore integrity

Polyfluoroacrylate (PFA) is a hydrophobic and oleophobic polymer that is soluble in high pressure carbon dioxide (CO 2 ). In this study, the ability of PFA-CO 2 solutions to greatly reduce the apparent permeability of split or cracked Portland cement cylindrical samples is assessed. The apparent permeability values of confined samples were determined before and after treatment with PFA-CO 2 solutions. In four tests, PFA-CO 2 solutions were continuously displacing pure CO 2 from the cracked cement and the decrease in apparent permeability due to PFA adsorption and wettability alteration was monitored. The lowest apparent permeability cracked cement sample (81 nD) was completely sealed with a very small amount of solution. Samples with initial apparent permeabilities of 89 μD and 29.4 mD exhibited 92% and 99% reductions in permeability, respectively, before the experiments had to be stopped because of the excessively large increase in pressure drop. A 50% reduction in apparent permeability was observed with a 3.80 mD sample. Four other split cement samples (bound together with tape) with an initial apparent permeability in the 9.0–70 mD range were removed from the core holder and immersed in a PFA-CO 2 solution for 24 h to allow for PFA adsorption. Then the PFA-CO 2 solution was depressurized, allowing for the deposition of additional PFA from the solution within the crack as the pressure fell below the cloud point pressure of the PFA-CO 2 solution. These four samples were then confined again in a core holder and apparent permeability reductions of 29–93% were observed. Finally, results from these eight experiments indicates that the more substantial reductions in the nD – mD apparent permeability of the cracked cement correlated to lower initial crack permeability, higher PFA concentration, and slower injection rate of the PFA-CO 2 solution into the crack.

58 GEOSCIENCES↗

DOE OSTI2022

Macrovoid resolved simulations of transport through HPRO relevant membrane geometries

Modeling the transport properties such as diffusivity and permeability of high pressure reverse osmosis (HPRO) membranes is critical for the selection and manufacture of membranes suitable for operation under high pressure. These properties can be significantly affected by the changes in heterogeneous pore structures due to compaction. Here, the modeling platform presented in this work resolves the two scale porosity in HPRO relevant membranes. A synthetic membrane geometry is constructed based on available experimental visualizations of pore structures. The simulations directly capture the flow channeling that results from a combination of material properties and geometric features of the macrovoids. A parametric study is presented to account for the transition of flow characteristics from a material governed regime to a macrovoid governed regime. Permeability of the membrane is evaluated using the simulation data and compared with an existing model that scales with the square of tortuosity over a range of material properties. The model is found to perform well under a narrow range of tortuosity while deviating from the calculated permeabilities at extreme conditions. The effective permeability of the membrane is found to vary by at least two orders of magnitude between the two flow regimes. It is also observed that tortuosity is a bounded property with its upper limit determined by the macrovoid geometry. Consequently, the tortuosity based correlations fail near a flow regime that is mainly governed by the macrovoids. The modeled permeability can be more than an order of magnitude smaller than the simulation result. A new model based on flux-weighted porosity of a membrane is introduced and its correlation with tortuosity is studied. The model agrees with the simulated data as, in addition to tortuosity, it also accounts for the flux partition within and outside the flow channels. Such correlations enable extending the existing understanding of flow characteristics to enhance predictability of porous media models.

42 ENGINEERING↗

DOE OSTI2025

Derivation of A Representative Elementary Volume (REV) for Upscaled Two-Phase Flow in Porous Media

Relative permeability plays an important role in the upscaling of multiphase flow in porous media from the pore scale to the Darcy scale. The entire concept of relative permeability is contingent on the existence of a representative elementary volume (REV). As we move to smaller samples to measure relative permeability, such as with digital core analysis, the concept of a classical REV has become increasingly unlikely when using the conventional approach to defining a representative volume. The “‘conventional”’ understanding of an REV is that a large enough volume must be considered such that spatial variability averages out. In digital rock methods, such as pore-scale simulations based on micro-computed tomography (CT) images, the domain size is typically 2 to 4 mm. This is approximately the length scale of a single-phase flow REV using the classic REV approach. However, the single-phase perspective does not consider the complex dynamics and fluctuations often observed in multiphase flow systems, even at centimeter-scale experiments and/or simulations. A fundamental question is, therefore, whether the domain size commonly used in digital rock simulations can provide a consistent energy budget such that the concept of relative permeability exists. Based on first principles, relative permeability accounts for the rate of energy dissipated in a stationary process. If the dynamics are fluctuating, the energy dissipated can vary but will average out over a long enough timescale. The key to determining the validity of the relative permeability is the timescale of the measurement, not the spatial scale. The conventional REV theory assumes that spatial, temporal, and ensemble averages are equivalent in an ergodic system, but it does not provide a way to test this assumption. We provide a formal way to identify the timescale where the relative permeability accurately captures energy dissipation as a way to validate relative permeability measurements and quantitatively assess their accuracy. This result will be tested for a practical SCAL test, determining how long a flow experiment needs to be run to accurately characterize the rate of energy dissipation by the flow. The outcome will be a best practice guide for the determination of relative permeability from core-scale experiments and/or digital core simulations that ensure the energy budget is fully accounted for in the relative permeability coefficient.

Mcclure, James [Virginia Tech, Blacksburg]↗

DOE OSTI2018

Assessing the Geomechanical Response of CO 2 Disposal in Flood Basalt Reservoirs

In this work, we complete a multi-scale investigation of the physical processes governing geologic CO 2 sequestration in basalt reservoirs. This work integrates (i) laboratory measurements of relative permeability in a basalt fracture, (ii) theoretical modeling to understand how relative permeability uncertainty affects geomechanical performance attributes of basalt reservoirs, (iii) outcrop-scale simulation to identify the characteristics of vertical CO 2 flow in a basalt fracture network, and (iv) regional-scale assessment of permeability architecture in the Columbia River Basalt Group (CRBG). These individual studies are combined into a site-scale stochastic model of geologic CO 2 sequestration in the Columbia River Plateau, which shows how bulk and relative permeability variability affects geomechanical reservoir integrity and storage capacity of flood basalt reservoirs. This project resulted in a novel laboratory technique that combines X-ray CT and micro-PET scanning to calculate the relative permeability curves for a horizontal fracture in basalt. We also discovered that permeability on the Columbia River Plateau exhibits directionally-dependent spatial correlation, which our analysis suggests is a result of loading-induced subsidence. This analysis further discovered that permeability in the CRBG may increase at depth due to bending moment stresses. In the context of CO 2 sequestration, this result implies that storage capacity and injectivity may actually increase at depths beyond ~1 km. Our outcrop-scale investigation found that buoyant, free-phase CO 2 tends to accumulate at fracture intersections, which inhibits vertical flow over 10+ year timescales and may facilitate both physical and chemical trapping as fluid mobility decreases. At the site-scale, we find that in flood basalt reservoirs the spatial configuration of reservoir permeability exhibits substantial control on CO 2 injectivity. We utilized known borehole geology from the Wallula Basalt Sequestration Pilot Project to develop 50 equally probable permeability configurations and found that a single injection well operating at 95% of the borehole breakout pressure can deliver 0.12 to 2.0 million metric tons of CO 2 per year (MMT CO 2 per year). This maximum injection rate can support a 1,000 MW gas-fired power plant with a single injection well.

58 GEOSCIENCES↗

DOE OSTI2015

Regional and Local Geothermal Potential Evaluation: Examples from the Great Basin, USA, Iceland and East Africa

In both tectonically and magmatically mediated geothermal systems, geologic structures play a crucial role in focusing geothermal fluid circulation in the upper crust. In a variety of geothermal provinces worldwide, normal and strike-slip faults, caldera related faults, as well as fractures and fissures related to dikes and other magmatic intrusions generate the fracture permeability utilized for geothermal circulation. Localities where the above structures intersect and interact are characterized by the most robust generation and maintenance of fracture permeability, and therefore are the most favorable conduits for geothermal circulation. We present an evaluation of the structural geometries that tend to generate high density faulting and fracturing and an evaluation of the orientations of those structures with respect to the ambient stress conditions in three regions of high geothermal potential; The Great Basin, USA, Iceland, and east Africa. These analyses provide first-order constraints on areas that have favorable conditions for permeability and where future exploration for geothermal resources could be focused. In the Great Basin, USA, fault step-overs, fault terminations and accommodation zones are among the most common structural settings of known geothermal activity. Analysis of the geometry of these structures with respect to the ambient stress conditions reveals locations where faults associated with these structures are favorably oriented for enhanced fracture permeability. In magmatically active extensional provinces, like Iceland and east Africa, heat associated with shallow magmatic intrusions beneath volcanic centers drives geothermal circulation in near-surface fracture permeability conduits. Accentuated fault and fracture density and fracture permeability is generated by both axially oriented faults and fractures associated with axial rift zones and radially oriented structures near volcanic centers. Although heat from magmatic intrusion is most robust at volcanic centers, a high density of young intrusions may actually result in decreased permeability through closing of fracture networks. The locations of these three types of features; axial faults and fractures, radial structures, and young magmatic intrusions, all play a critical role in determining the most favorable locations for fracture permeability and fluid flow in magmatic geothermal systems. Within and around the margins of volcanic centers, where radial structures associated with volcanic centers interact and intersect with axially oriented structures associated with axial extension are the most favorable locations for fracture permeability and geothermal fluid circulation in magmatic extensional geothermal systems.

15 GEOTHERMAL ENERGY↗

NASA NTRS1993

Verification of a two-dimensional infiltration model for the resin transfer molding process

A two-dimensional finite element model for the infiltration of a dry textile preform by an injected resin was verified. The model, which is based on the finite element/control volume technique, determines the total infiltration time and the pressure increase at the mold inlet associated with the RTM process. Important input data for the model are the compaction and permeability behavior of the preform along with the kinetic and rheological behavior of the resin. The compaction behavior for several textile preforms was determined by experimental methods. A power law regression model was used to relate fiber volume fraction to the applied compaction pressure. Results showed a large increase in fiber volume fraction with the initial application of pressure. However, as the maximum fiber volume fraction was approached, the amount of compaction pressure required to decrease the porosity of the preform rapidly increased. Similarly, a power law regression model was used to relate permeability to the fiber volume fraction of the preform. Two methods were used to measure the permeability of the textile preform. The first, known as the steady state method, measures the permeability of a saturated preform under constant flow rate conditions. The second, denoted the advancing front method, determines the permeability of a dry preform to an infiltrating fluid. Water, corn oil, and an epoxy resin, Epon 815, were used to determine the effect of fluid type and viscosity on the steady state permeability behavior of the preform. Permeability values measured with the different fluids showed that fluid viscosity had no influence on the permeability behavior of 162 E-glass and TTI IM7/8HS preforms. Permeabilities measured from steady state and advancing front experiments for the warp direction of 162 E-glass fabric were similar. This behavior was noticed for tests conducted with corn oil and Epon 815. Comparable behavior was observed for the warp direction of the TTI IM7/8HS preform and corn oil. Mold filling and flow visualization experiments were performed to verify the analytical computer model. Frequency dependent electromagnetic sensors were used to monitor the resin flow front as a function of time. For the flow visualization tests, a video camera and high resolution tape recorder were used to record the experimental flow fronts. Comparisons between experimental and model predicted flow fronts agreed well for all tests. For the mold filling tests conducted at constant flow rate injection, the model was able to accurately predict the pressure increase at the mold inlet during the infiltration process. A kinetics model developed to predict the degree of cure as a function of time for the injected resin accurately calculated the increase in the degree of cure during the subsequent cure cycle.

Hammond, Vincent H.↗

DOE OSTI2020

Petrophysical and geomechanical properties of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well

Knowledge of petrophysical and geomechanical properties of gas hydrate-bearing sediments are essential for predicting reservoir response due to gas production from gas hydrate reservoirs. That information will be critical parameters for designing production well completion such as specification of depressurization pump, water storage tank, and mesh size of sand screen. In December 2018, Stratigraphic Test Well Hydrate-01 was drilled in the western part of the Prudhoe Bay Unit, Alaska North Slope as part of the technical planning effort for a future long-term production test by collaborative team of DOE/NETL, USGS, and MH21-S (Boswell et al., 2020, Collett et al., 2020, Okinaka et al., 2020). Data set of logging-while-drilling (LWD) were acquired (Haines et al., 2020, Suzuki et al., 2019) and core sampling depth was determined on-site.Side-wall pressure coring was conducted to recover gas hydrate-bearing sediments from two reservoir sections named Unit-B and Unit-D. A total of 34 cores were successfully recovered by 5 runs of a wire-line deployed pressure corer (CoreVault® System - Halliburton). Core analysis scheme of this project are shown in Figure 1. All cores were quenched in liquid nitrogen while at high pressure in the laboratory of Stratum Reservoir, LLC. at Anchorage (Figure 1, a)). And the cores were removed from the pressure corer autoclave with temperature support of dry ice and stored under liquid nitrogen at atmospheric pressure. 19 damaged cores were processed to index property measurements directly such as grain size, grain density. 4 of another 17 cores were depressurized and trimmed for making a plug to analyze petrophysical properties of host sediments. Unsteady-state permeability test was conducted to obtain relative water permeability to gas and core scale NMR T2 distribution measurement was performed for evaluating pore size distribution at Houston (Figure 1, b)). Remained high quality 13 cores were preserved with gas hydrate for advanced laboratory analysis. National Institute of Advanced Industrial Science and Technology, as a part of the Japanese National Hydrate Research Program (MH21-S, funded by Ministry of Economy, Trade and Industry), received the samples at Sapporo, Japan for advanced core analysis. High-resolution X-ray CT was used to analyze the quality of the samples, which showed undisturbed lithological layers. Cores were lathed into cylindrical shape and distributed for multi property measurements (Figure 1, c)).<p>As a result, sediment from Unit-D is categorized as silty sand at ~37% porosity with ~80% gas hydrate saturation. An average hydration number n = 6.16 was measured by Raman spectroscopy. An average intrinsic permeability of ~400 mD and in situ effective permeability (with hydrate) on the order of ~10 mD. The Unit B recovered cores consisted of well sorted sand at ~40% porosity with ~95% gas hydrate saturation. An average intrinsic permeability of ~1 Darcy and in situ effective permeability on the order of ~30 mD was measured for the Unit B cores. There was a small permeability reduction due to porosity loss with increasing effective stress that simulated consolidation behavior along with depressurization in the highly permeable sandy sediment. The apparent minimum change in porosity and permeability may be caused by the low compressibility of quartz sand grains in the recovered cores. XRD and thermal conductivity analysis also suggested high quartz content. Triaxial compression tests established internal friction angles based on the Mohr-Coulomb's failure criterion, which are 40° for hydrate-bearing sediment and 29.8° for hydrate free sediment.</p>

Yoneda, Jun↗

DOE OSTI2015

Generalized lattice Boltzmann model for flow through tight porous media with Klinkenberg's effect

We report that gas slippage occurs when the mean free path of the gas molecules is in the order of the characteristic pore size of a porous medium. This phenomenon leads to Klinkenberg's effect where the measured permeability of a gas (apparent permeability) is higher than that of the liquid (intrinsic permeability). A generalized lattice Boltzmann model is proposed for flow through porous media that includes Klinkenberg's effect, which is based on the model of Guo et al. [Phys. Rev. E 65, 046308 (2002)]. The second-order Beskok and Karniadakis-Civan's correlation [A. Beskok and G. Karniadakis, Microscale Thermophys. Eng. 3, 43 (1999) and F. Civan, Transp. Porous Med. 82, 375 (2010)] is adopted to calculate the apparent permeability based on intrinsic permeability and the Knudsen number. Fluid flow between two parallel plates filled with porous media is simulated to validate the model. Simulations performed in a heterogeneous porous medium with components of different porosity and permeability indicate that Klinkenberg's effect plays a significant role on fluid flow in low-permeability porous media, and it is more pronounced as the Knudsen number increases. Lastly, fluid flow in a shale matrix with and without fractures is also studied, and it is found that the fractures greatly enhance the fluid flow and Klinkenberg's effect leads to higher global permeability of the shale matrix.

71 CLASSICAL AND QUANTUM MECHANICS, GENERAL PHYSIC↗

DOE OSTI2019

Comprehensive study of the interactions between the critical dimensionless numbers associated with multiphase flow in 3D porous media

Multiphase flow in porous media is of signifcant interest in many engineering applications, such as geologic carbon sequestration, enhanced oil recovery, and groundwater contamination and remediation. In order to advance the fundamental understanding of multiphase flow in complex three-dimensional (3D) porous media, the interactions between the critical dimensionless numbers, including the contact angle, viscosity ratio, and capillary (Ca) number, were explored using X-ray micro-computed tomography (micro-CT) scanning and lattice Boltzmann (LB) modeling. In this study, the 3D pore structure information was extracted from micro-CT images and then used as interior boundary conditions of flow modeling in a pore-scale LB simulator to simulate multiphase flow within the pore space. A Berea sandstone sample was scanned and then two-phase flow LB simulations were performed based on the micro-CT images. The LB-simulated water/CO 2 distributions agreed well with the micro-CT scanned images. Simulation findings showed that a decreasing contact angle causes a decrease in wetting-fluid relative permeability and an increase in non-wetting fluid relative permeability. A rising Ca number increases both wetting and non-wetting fluid relative permeabilities. An increasing viscosity ratio (the ratio of non-wetting fluid viscosity to wetting fluid viscosity) facilitates the increase of non-wetting fluid relative permeability and mitigates the reduction of wetting fluid relative permeability, when the contact angle decreases continuously. The primary novel finding of this study is that the viscosity ratio affects the rate of change of the relative permeability curves for both phases when the contact angle changes continuously. To date, we believe it is the first time that comprehensive interactions between these dimensionless numbers are demonstrated in a sandstone sample based on real 3D structures. We also investigated the role of the changes of flow direction and sample location on relative permeability curves. Simulation results showed that the change in non-wetting fluid relative permeability was larger when the flow direction was switched from vertical to horizontal, which indicated that there was stronger anisotropy in larger pore networks that were primarily occupied by the non-wetting fluid.

42 ENGINEERING↗

DOE OSTI2017

Study of hydraulic fracturing processes in shale formations with complex geological settings

Hydraulic fracturing has been applied to extract gas from shale-gas reservoirs. Complicated geological settings, such as spatial variability of the rock mass properties, local heterogeneities, complex in situ stress field, and pre-existing bedding planes and faults, could make hydraulic fracturing a challenging task. In order to effectively and economically recover gas from such reservoirs, it is crucial to explore how hydraulic fracturing performs in such complex geological settings. For this purpose, numerical modelling plays an important role because such conditions cannot be reproduced by laboratory experiments. This study focuses on the analysis of the influence of confining formations and pre-existing bedding planes and faults on the hydraulically-induced propagation of a vertical fracture, which will be called injection fracture, in a shale-gas reservoir. An elastic-brittle model based on material property degradation was implemented in a 2D finite-difference scheme and used for rock elements subjected to tension and shear failure. A base case is considered, in which the ratio SR between the magnitudes of the horizontal and vertical stresses, the permeability k c of the confining formations, the elastic modulus E p and initial permeability k p of the bedding plane and the initial fault permeability k F are fixed at reasonable values. In addition, the influence of multiple bedding planes, is investigated. Changes in pore pressure and permeability due to high pressure injection lasting 2 h were analysed. Results show that in our case during the injection period the fracture reaches the confining formations and if the permeability of those layers is significantly larger than that of the shale, the pore pressure at the extended fracture tip decreases and fracture propagation becomes slower. After shut-in, the pore pressure decreases more and the fracture does not propagate any more. For bedding planes oriented perpendicular to the maximum principal stress direction and with the same elastic properties as the shale formation, results were found not to be influenced by their presence. In such a scenario, the impact of multiple bedding planes on fracture propagation is negligible. On the other hand, a bedding plane softer than the surrounding shale formation leads to a fracture propagation asymmetrical vertically with respect to the centre of the injection fracture with a more limited upward fracture propagation. A pre-existing fault leads to a decrease in fracture propagation because of fault reactivation with shear failure. This results in a smaller increase in injection fracture permeability and a slight higher injection pressure than that observed without the fault. Results of a sensitivity analysis show that fracture propagation is influenced by the stress ratio SR, the permeability k c of the confining formations and the initial permeability k p of the bedding plane more than the other major parameters.

58 GEOSCIENCES↗

DOE OSTI2018

Interaction Between Proppant Compaction and Single-/Multiphase Flows in a Hydraulic Fracture

Understanding proppant-transport and -deposition patterns in a hydraulic fracture is vital for effective and economical production of petroleum hydrocarbons. In this research, a numerical-modeling approach, combining the discrete-element method (DEM) with single-/multiphase lattice Boltzmann (LB) simulation, was adopted to advance understanding of the interaction between reservoir depletion, proppant-particle compaction, and single-/multiphase flows in a hydraulic fracture. DEM was used to simulate effective-stress increase and the resultant proppant-particle movement and rearrangement during the process of reservoir depletion caused by hydrocarbon production. Simulated pore structure of the proppant pack was extracted and used as boundary conditions in the LB simulation to calculate the time-dependent permeability of the proppant pack. We first validated the DEM-LB numerical work flow, and the simulated proppant-pack permeabilities as functions of effective stress were in good agreement with laboratory measurements. Furthermore, three proppant packs with the same average particle diameter but different diameter distributions were generated to study the role of proppant-size heterogeneity (variation in particle diameter). Specifically, we used the coefficient of variation (COV) of diameter, defined as the ratio of standard deviation of diameter to mean diameter, to characterize the heterogeneity of particle size. We obtained proppant-pack porosity, permeability, and fracture-width reduction (closure distance) as functions of effective stress. Under the same effective stress, a proppant pack with a higher diameter COV had lower porosity and permeability and larger fracture-width reduction. This was because the high diameter COV gave rise to a wider diameter distribution of proppant particles; smaller particles were compressed into the pore space between larger particles with increasing stress, leading to larger closure distance and lower porosity and permeability. With multiphase LB simulation, relative permeability curves were obtained, which are critical for larger-scale reservoir simulations under various effective stresses. The relative permeability of the oil phase was more sensitive to changes in geometry and stress, compared with the wetting phase. This was because the oil phase occupied larger pores; compaction of the proppant pack affected the structure of the pores, because the pores were farther from the grain contacts and thus more susceptible to collapse. It is also interesting to note that when effective stress increased continuously, oil relative permeability increased first and then decreased. This nonmonotonic behavior was the result of the nonmonotonic development of pore structure and oil connectivity under increasing stress.

Fan, Ming↗

NASA NTRS1992

Determination of forces in a magnetic bearing actuator - Numerical computation with comparison to experiment

Calculations of the forces exerted on a journal by a magnetic bearing actuator are presented, along with comparisons to experimentally measured forces. The calculations are based on two-dimensional solutions for the flux distribution in the metal parts and free space, using finite but constant permeability in the metals. Above a relative permeability of 10,000 the effects of changes in permeability are negligible, but below 10,000 decreases in permeability cause significant decreases in the force. The calculated forces are shown to depend on the metal permeability more strongly when the journal is displaced from its centered position. The predicted forces in the principal attractive direction are in good agreement with experiment when a relatively low value of permeability is chosen. The forces measured normal to the axis of symmetry when the journal is displaced from that axis, however, are significantly higher than predicted by theory, even with a value of relative permeability larger than 5000. These results indicate a need for further work including nonlinear permeability distributions.

Knight, J. D.↗

DOE OSTI2017

The influence of interfacial slip on two-phase flow in rough pores

The migration and trapping of supercritical CO 2 (scCO 2 ) in geologic carbon storage is strongly dependent on the geometry and wettability of the pore network in the reservoir rock. During displacement, resident fluids may become trapped in the pits of a rough pore surface forming an immiscible two-phase fluid interface with the invading fluid, allowing apparent slip flow at this interface. We present a two-phase fluid dynamics model, including interfacial tension, to characterize the impact of mineral surface roughness on this slip flow. We show that the slip flow can be cast in more familiar terms as a contact-angle (wettability)-dependent effective permeability to the invading fluid, a nondimensional measurement which relates the interfacial slip to the pore geometry. The analysis shows the surface roughness-induced slip flow can effectively increase or decrease this effective permeability, depending on the wettability and roughness of the mineral surfaces. Configurations of the pore geometry where interfacial slip has a tangible influence on permeability have been identified. The results suggest that for large roughness features, permeability to CO 2 may be enhanced by approximately 30% during drainage, while the permeability to brine during reimbibition may be enhanced or diminished by 60%, depending on the contact angle with the mineral surfaces and degrees of roughness. For smaller roughness features, the changes in permeability through interfacial slip are small. As a result, a much larger range of effective permeabilities are suggested for general fluid pairs and contact angles, including occlusion of the pore by the trapped phase.

54 ENVIRONMENTAL SCIENCES↗

DOE OSTI2021

Mafic explosive volcanism at Llaima Volcano: 3D x-ray microtomography reconstruction of pyroclasts to constrain shallow conduit processes

Abstract Mafic volcanic activity is dominated by effusive to mildly explosive eruptions. Plinian and ignimbrite-forming mafic eruptions, while rare, are also possible; however, the conditions that promote such explosivity are still being explored. Eruption style is determined by the ability of gas to escape as magma ascends, which tends to be easier in low-viscosity, mafic magmas. If magma permeability is sufficiently high to reduce bubble overpressure during ascent, volatiles may escape from the magma, inhibiting violent explosive activity. In contrast, if the permeability is sufficiently low to retain the gas phase within the magma during ascent, bubble overpressure may drive magma fragmentation. Rapid ascent may induce disequilibrium crystallization, increasing viscosity and affecting the bubble network with consequences for permeability, and hence, explosivity. To explore the conditions that promote strongly explosive mafic volcanism, we combine microlite textural analyses with synchrotron x-ray computed microtomography of 10 pyroclasts from the 12.6 ka mafic Curacautín Ignimbrite (Llaima Volcano, Chile). We quantify microlite crystal size distributions (CSD), microlite number densities, porosity, bubble interconnectivity, bubble number density, and geometrical properties of the porous media to investigate the role of magma degassing processes at mafic explosive eruptions. We use an analytical technique to estimate permeability and tortuosity by combing the Kozeny-Carman relationship, tortuosity factor, and pyroclast vesicle textures. The groundmass of our samples is composed of up to 44% plagioclase microlites, > 85% of which are < 10 µm in length. In addition, we identify two populations of vesicles in our samples: (1) a convoluted interconnected vesicle network produced by extensive coalescence of smaller vesicles (> 99% of pore volume), and (2) a population of very small and completely isolated vesicles (< 1% of porosity). Computed permeability ranges from 3.0 × 10 −13 to 6.3 × 10 −12 m 2 , which are lower than the similarly explosive mafic eruptions of Tarawera (1886; New Zealand) and Etna (112 BC; Italy). The combination of our CSDs, microlite number densities, and 3D vesicle textures evidence rapid ascent that induced high disequilibrium conditions, promoting rapid syn-eruptive crystallization of microlites within the shallow conduit. We interpret that microlite crystallization increased viscosity while simultaneously forcing bubbles to deform as they grew together, resulting in the permeable by highly tortuous network of vesicles. Using the bubble number densities for the isolated vesicles (0.1-3 −3 × 10 4 bubbles per mm 3 ), we obtain a minimum average decompression rate of 1.4 MPa/s. Despite the textural evidence that the Curacautín magma reached the percolation threshold, we propose that rapid ascent suppressed outgassing and increased bubble overpressures, leading to explosive fragmentation. Further, using the porosity and permeability of our samples, we estimated that a bubble overpressure > 5 MPa could have been sufficient to fragment the Curacautín magma. Other mafic explosive eruptions report similar disequilibrium conditions induced by rapid ascent rate, implying that syn-eruptive disequilibrium conditions may control the explosivity of mafic eruptions more generally.

Valdivia, Pedro↗

DOE OSTI2024

The Impact of Wettability on the Co-moving Velocity of Two-Fluid Flow in Porous Media

Abstract The impact of wettability on the co-moving velocity of two-fluid flow in porous media is analyzed herein. The co-moving velocity, developed by Roy et al. (Front Phys 8:4, 2022), is a novel representation of the flow behavior of two fluids through porous media. Our study aims to better understand the behavior of the co-moving velocity by analyzing simulation data under various wetting conditions. We analyzed 46 relative permeability curves based on the Lattice–Boltzmann color fluid model and two experimentally determined relative permeability curves. The analysis of the relative permeability data followed the methodology proposed by Roy et al. (Front Phys 8:4, 2022) to reconstruct a constitutive equation for the co-moving velocity. Surprisingly, the coefficients of the constitutive equation were found to be nearly the same for all wetting conditions. On the basis of these results, a simple approach was proposed to reconstruct the relative permeability of the oil phase using only the co-moving velocity relationship and the relative permeability of the water phase. This proposed method provides new information on the interdependence of the relative permeability curves, which has implications for the history matching of production data and the solution of the associated inverse problem. The research findings contribute to a better understanding of the impact of wettability on fluid flow in porous media and provide a practical approach for estimating relative permeability based on the co-moving velocity relationship, which has never been shown before.

Engineering↗

DOE OSTI2017

Regression-based reduced-order models to predict transient thermal output for enhanced geothermal systems

Reduced-order modeling is a promising approach, as many phenomena can be described by a few parameters/mechanisms. An advantage and attractive aspect of a reduced-order model is that it is computational inexpensive to evaluate when compared to running a high-fidelity numerical simulation. A reduced-order model takes couple of seconds to run on a laptop while a high-fidelity simulation may take couple of hours to run on a high-performance computing cluster. The goal of this paper is to assess the utility of regression-based reduced-order models (ROMs) developed from high-fidelity numerical simulations for predicting transient thermal power output for an enhanced geothermal reservoir while explicitly accounting for uncertainties in the subsurface system and site-specific details. Numerical simulations are performed based on equally spaced values in the specified range of model parameters. Key sensitive parameters are then identified from these simulations, which are fracture zone permeability, well/skin factor, bottom hole pressure, and injection flow rate. We found the fracture zone permeability to be the most sensitive parameter. The fracture zone permeability along with time, are used to build regression-based ROMs for the thermal power output. The ROMs are trained and validated using detailed physics-based numerical simulations. Finally, predictions from the ROMs are then compared with field data. We propose three different ROMs with different levels of model parsimony, each describing key and essential features of the power production curves. The coefficients in the proposed regression-based ROMs are developed by minimizing a non-linear least-squares misfit function using the Levenberg–Marquardt algorithm. The misfit function is based on the difference between numerical simulation data and reduced-order model. ROM-1 is constructed based on polynomials up to fourth order. ROM-1 is able to accurately reproduce the power output of numerical simulations for low values of permeabilities and certain features of the field-scale data. ROM-2 is a model with more analytical functions consisting of polynomials up to order eight, exponential functions and smooth approximations of Heaviside functions, and accurately describes the field-data. At higher permeabilities, ROM-2 reproduces numerical results better than ROM-1, however, there is a considerable deviation from numerical results at low fracture zone permeabilities. ROM-3 consists of polynomials up to order ten, and is developed by taking the best aspects of ROM-1 and ROM-2. ROM-1 is relatively parsimonious than ROM-2 and ROM-3, while ROM-2 overfits the data. ROM-3 on the other hand, provides a middle ground for model parsimony. Based on R 2 -values for training, validation, and prediction data sets we found that ROM-3 is better model than ROM-2 and ROM-1. For predicting thermal drawdown in EGS applications, where high fracture zone permeabilities (typically greater than 10 –15 m 2 ) are desired, ROM-2 and ROM-3 outperform ROM-1. As per computational time, all the ROMs are 10 4 times faster when compared to running a high-fidelity numerical simulation. In conclusion, this makes the proposed regression-based ROMs attractive for real-time EGS applications because they are fast and provide reasonably good predictions for thermal power output.

58 GEOSCIENCES↗