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CO 2 geological storage in saline aquifers results in acidification of resident brine. Chemical reactions between acidified brine and rock minerals lead to dissolution and precipitation of minerals at various time scales. Mineral dissolution and precipitation are often neglected in assessing the mechanical integrity of target storage formations, yet, changes in rock strength and deformational behavior can impact trapping mechanisms. This study shows the impact of exposure to CO 2 -charged brine on shear strength and stiffness of various outcrop rocks evaluated through triaxial testing. The tested rocks were exposed to CO 2 -charged brine over geological time at a naturally occurring near-surface seepage along the Little Grand Wash Fault and Salt Wash Grabens, which include the Crystal Geyser site near the town of Green River, Utah. Prior work suggests that this site provides a near-surface structural analog for possible fault-controlled CO 2 leakage over time scales that exceed expected injection time scales (10–100 years). Results show mechanical alteration in various aspects: (1) CO 2 -charged brine alteration at near-surface conditions results in mineral dissolution/precipitation and reduction of shear strength and brittleness of Entrada sandstone and Summerville siltstone samples, and (2) carbonate precipitation in fractured Mancos shale leads to matrix stiffening and fracture mineralization resulting in overall stiffer and likely tighter shale. Additional discrete element simulations coupled with a bonded-particle-model confirm the role of cement bond size alteration as one of the main controls for rock chemo-mechanical alteration in sandstones. The chemo-mechanical alteration path that mimics cement dissolution (under stressed subsurface conditions) results in vertical compaction and lateral stress relaxation. Overall, results show that rock exposure to CO 2 -charged brine can impart distinct petrophysical and geomechanical changes according to rock lithology and location with respect to major CO 2 conduits. While mineral dissolution in the storage rock may result in undesired reservoir strains and changes of stresses, mineral precipitation downstream from a leakage path can help seal potentially induced fractures. [ABSTRACT FROM AUTHOR]

• Modeling of tracer transport in two-phase flow in capillary-dominated porous media. • Hydrodynamic dispersion, partition coefficient, and solute adsorption are examined. • Accurate modeling of tracer transfer by spontaneous imbibition in porous media. Transport of chemical tracers in porous media is an important physical mechanism for applications in oil reservoir characterization, aquifer remediation, and CO 2 storage. Although numerous analytical solutions exist to model the flow of solutes under single-phase flow, the modeling of solute transport in two-phase media driven by imbibition has been insufficiently examined. In tight porous media and the matrix of fractured reservoirs, spontaneous imbibition (SI) represents a key driving mechanism for fluid infiltration because the low permeability in these systems results in negligible transport by advection. Here, we present a new semi-analytical solution to model the transport of chemical tracers under one-dimensional countercurrent SI in oil–water porous media. The model presented is derived from the analysis of fluid imbibition driven by capillarity and numerically solved as a function of water distribution. We model ideal and partitioning tracers to examine the contacted region and estimate the average oil saturation in capillary-dominated media under countercurrent SI. The concentration profiles obtained with the derived model show an excellent agreement against numerical simulation results, verifying that the semi-analytical solution accurately models the mechanisms of partitioning, hydrodynamic dispersion, and adsorption. The concentration profiles exhibit a significant delay in displacement behind the imbibition front when hydrodynamic dispersion is ignored and for high partitioning coefficients, demonstrating the importance of determining these properties under two-phase flow conditions. We consider that our solution derived represents an accurate alternative to time-consuming simulations that can be extended for the analysis of tracers in fractured reservoirs to estimate oil saturation in the matrix medium. [ABSTRACT FROM AUTHOR]

A semi-analytical solution for the transient advection–diffusion–reaction problem within finite and semi-infinite ducts is derived. The solution allows for general radial- and time-dependent inlet/outlet conditions, complex boundary conditions on the duct wall including adsorption and decay, and arbitrary velocity profiles of the transporting fluid. The only numerical step of the solution is the inverse Laplace transform in the time variable. Therefore, the approach also produces fully analytical steady-state solutions. The solution is verified against computational fluid dynamics (CFD) simulations under various boundary conditions and velocity profiles (Newtonian and power-law), and in all cases good agreement is obtained. Although theoretically applicable to all regimes, the solution is computationally difficult at very high Peclet numbers and very early times due to numerical instabilities as a result of finite precision arithmetic of computers. A convergence analysis is conducted to delineate the boundaries of this limit for two important cases. The solution was derived using a new approach for solving two-dimensional partial differential equations (PDEs) with non-constant coefficients which parallels the Frobenius and power series methods for solving ordinary differential equations (ODEs). The approach reduces the original PDE to a single infinite-order ODE with constant coefficients. The approach is suspected to provide solutions to a large class of PDEs of this type. The solution may find applications in a number of engineering and/or biomedical fields, it can be used to verify numerical simulators, and serve as a simple and easy-to-implement alternative where access to numerical simulators is not available. [ABSTRACT FROM AUTHOR]

We report the discovery of novel regimes of calcium carbonate dissolution in micron-scale confined spaces through microfluidic experiments. In the experiments, hydrochloric acid is injected into a microfluidic chamber with pre-deposited calcium carbonate solids. As the acid flow rate is decreased, the dissolution of calcium carbonate transits from a liquid/solid single-phase reactive transport regime to a gas/liquid/solid two-phase one. The two-phase regime further splits into two different regimes, one with fluctuating and the other with nonfluctuating gaseous CO 2 phase. We name the three regimes as "Nongaseous", "Gaseous Breathing", and "Gaseous Nonbreathing". The experimental observations are reproduced and interpreted by mathematical modeling. Results show that the regimes are controlled by the ratio of H+ concentration and saturated CO 2 concentration, the Peclet number and the second Damkohler number. Dimensionless diagrams distinguishing different regimes are presented and an empirical relationship is proposed. Our results offer insights into various engineering and natural processes, e.g., geological carbon storage, petroleum reservoir acidizing, Karst dissolution, and others that are governed by small scale multiphase reactive flow physics. [ABSTRACT FROM AUTHOR]

Network modeling is a useful tool for investigating pore-scale behavior and in some cases for determining macroscopic information such as permeability, relative permeability, and capillary pressure. Physically representative network models are particularly useful because quantitative and predictive results can be obtained. In the past, network models have been used as stand-alone tools for predicting flow behavior at the pore scale. In these cases, simple boundary conditions such as a pressure gradient in one direction are generally imposed on the network. However, with the increasing emphasis on multiscale modeling techniques, the real potential of network models is as a bridge from the pore to the continuum scale. In this context, continuum-scale and pore-scale models are used jointly; pore-scale behavior is upscaled and substituted into a continuum-scale simulator. Methods for integrating these techniques are being developed, and one important question is how to match boundary conditions for the two scales. In this work, physically representative network models created from computer-generated sphere packings are coupled to adjacent continuum-scale models. By coupling the two regions, realistic boundary conditions are enforced, which reflect the heterogeneity of the packed bed as well as the resistance of the adjacent medium. Results of the direct coupling show that both pore-scale phenomena and macroscopic behavior (such as flowrate) are significantly different than when these same parameters are obtained by implementing simple (decoupled) boundary conditions. [Copyright &y& Elsevier]

Abstract: The flow of non-Newtonian fluids in packed beds and other porous media is important in several applications such as polymer processing, filtration, and enhanced oil recovery. Expressions for flowrate versus pressure gradient are desirable for a-priori prediction and for substitution into continuum models. In this work, physically representative network models are used to model the flow of shear-thinning fluids, including power-law and Ellis fluids. The networks are used to investigate the effects of fluid rheology and bed morphology on flow. A simple macroscopic model is developed for the flow of power-law and Ellis fluids in packed beds using results from the network model. The model has the same general functionality as those developed using the popular bundle-of-tubes approach. The constant , which appears in these models, is often directly derived from the tortuosity and a simple representation of the porous media. It is shown here that this can lead to incorrect and ambiguous values of the constant. Furthermore, the constant is a weak function of the shear-thinning index, indicating that no single bundle-of-tubes could ever properly model flow for a wide variety of shear-thinning fluids. The macroscopic model is compared to experimental data for shear-thinning fluids available in the literature. The model fits the data well when is treated as an experimental parameter. The best-fit values of vary, which is expected because even the constant C in the Blake–Kozeny equation varies depending on the source consulted. Additionally, physical effects, such as adsorption and filtration, as well as rheological effects such as viscoelasticity may affect the value of . We believe that in the absence of these effects, equals approximately 1.46 for packed beds of uniform spheres at relatively moderate values of the shear-thinning index . [Copyright &y& Elsevier]

CO 2 injection into geological formations shifts the geochemical equilibrium between the minerals and resident brine. The induced mineral-brine-CO 2 reactions can alter the reservoir rock strength and deformational behavior, which subsequently affects CO 2 storage mechanical integrity. This study attempts to investigate quantitatively the effect of mineral cement and particle dissolution through numerical modeling and validation of triaxial tests performed on unaltered and geologically altered Entrada Sandstone. We utilize a numerical model that couples the discrete element method (DEM) and the bonded-particle model (BPM) to perform simulations of triaxial tests on synthetic rocks that mimic tested rock samples under various confining stresses. Numerical results, in agreement with experimental evidence, show that both cement and particle dissolution significantly contribute to rock weakening in sandstone samples with carbonate/hematite cements and pore-filling carbonate. Sensitivity analyses show that the brittleness of DEM numerical samples is mostly conditioned by the cement bond size among all cement microscopic parameters. An alteration path that mimics the mineral dissolution under subsurface boundary conditions leads to (1) vertical compaction and horizontal stress relaxation in the reservoir rock and (2) transfer of stresses to adjacent strata that results in bond breakage and potentially natural fracture reactivation at a large scale. [ABSTRACT FROM AUTHOR]

The potential leakage of hydrocarbon fluids or carbon dioxide from subsurface formations is a primary concern in wellbore integrity, oil and gas production, and CO 2 storage. Leaky wells with fractured cement or debonded microannuli are common sources of subsurface fluid leakage. The hydrocarbon fluid or CO 2 can migrate through such pathways to shallower formations and ultimately to surface. Cement fractures may have apertures on the order of microns, which are difficult to seal with typical workover techniques. A material that provides low viscosity during the injection but much higher viscosity after injection, with a minimum pressure gradient to yield flow at the target zone, is a potentially effective approach to seal the leakage pathways through cement fractures. pH-triggered polymers are such a material: aqueous solutions with low viscosity at low pH, containing pH-sensitive microgels which viscosify upon neutralization to become highly swollen gels with substantial yield stress that can block fluid flow. For the wellbore leakage application, the large alkalinity of wellbore cement provides the required neutralization. Our coreflood and rheological experiments show that pH-triggered polymer sealants such as polyacrylic acid polymer provide a robust seal if the process is properly designed; however, its long-term applicability depends on the dynamic geochemical environment of the wellbore. The process comprises three stages: (1) injection of a chelating agent as the preflush to ensure a favorable environment for the polymer gel, (2) injection of polymer solution, and (3) shut-in for the polymer gelation. A systematic study was done to understand the conditions under which the polymer gel remains stable and effectively seals the leakage pathways. A numerical model, based on polymer rheological properties and governing mechanisms observed in the laboratory experiments, was developed to simulate the reactive flow and transport of pH-triggered polymers in narrow fractures. Comparison with experiments shows a generally good agreement, despite the relative simplicity of the model. The numerical model was used to investigate further the underlying mechanisms of the process. The results can be used to design effectively the remediation process for a known fracture aperture size of the target zone. [ABSTRACT FROM AUTHOR]

Shales and other unconventional or low permeability (tight) reservoirs house vast quantities of hydrocarbons, often demonstrate considerable water uptake, and are potential repositories for fluid sequestration. The pore-scale topology and fluid transport mechanisms within these nanoporous sedimentary rocks remain to be fully understood. Image-informed pore-scale models are useful tools for studying porous media: a debated question in shale pore-scale petrophysics is whether there is a representative elementary volume (REV) for shale models? Furthermore, if an REV exists, how does it differ among petrophysical properties? We obtain three dimensional (3D) models of the topology of microscale shale volumes from image analysis of focused ion beam-scanning electron microscope (FIB-SEM) image stacks and investigate the utility of these models as a potential REV for shale. The scope of data used in this work includes multiple local groups of neighboring FIB-SEM images of different microscale sizes, corresponding core-scale (milli- and centimeters) laboratory data, and, for comparison, series of two-dimensional (2D) cross sections from broad ion beam SEM images (BIB-SEM), which capture a larger microscale field of view than the FIB-SEM images; this array of data is larger than the majority of investigations with FIB-SEM-derived microscale models of shale. Properties such as porosity, organic matter content, and pore connectivity are extracted from each model. Assessments of permeability with single phase, pressure-driven flow simulations are performed in the connected pore space of the models using the lattice-Boltzmann method. Calculated petrophysical properties are compared to those of neighboring FIB-SEM images and to core-scale measurements of the sample associated with the FIB-SEM sites. Results indicate that FIB-SEM images below ∼5000 µm 3 volume (the largest volume analyzed) are not a suitable REV for shale permeability and pore-scale networks; i.e. field of view is compromised at the expense of detailed, but often unconnected, nanopore morphology. Further, we find that it is necessary to acquire several local FIB-SEM or BIB-SEM images and correlate their extracted geometric properties to improve the likelihood of achieving representative values of porosity and organic matter volume. Our work indicates that FIB-SEM images of microscale volumes of shale are a qualitative tool for petrophysical and transport analysis. Finally, we offer alternatives for quantitative pore-scale assessments of shale. [ABSTRACT FROM AUTHOR]

Multiple numerical approaches have been developed to simulate porous media fluid flow and solute transport at the pore scale. These include 1) methods that explicitly model the three-dimensional geometry of pore spaces and 2) methods that conceptualize the pore space as a topologically consistent set of stylized pore bodies and pore throats. In previous work we validated a model of the first type, using computational fluid dynamics (CFD) codes employing a standard finite volume method (FVM), against magnetic resonance velocimetry (MRV) measurements of pore-scale velocities. Here we expand that validation to include additional models of the first type based on the lattice Boltzmann method (LBM) and smoothed particle hydrodynamics (SPH), as well as a model of the second type, a pore-network model (PNM). The PNM approach used in the current study was recently improved and demonstrated to accurately simulate solute transport in a two-dimensional experiment. While the PNM approach is computationally much less demanding than direct numerical simulation methods, the effect of conceptualizing complex three-dimensional pore geometries on solute transport in the manner of PNMs has not been fully determined. We apply all four approaches (FVM-based CFD, LBM, SPH and PNM) to simulate pore-scale velocity distributions and (for capable codes) nonreactive solute transport, and intercompare the model results. Comparisons are drawn both in terms of macroscopic variables ( e.g. , permeability, solute breakthrough curves) and microscopic variables ( e.g. , local velocities and concentrations). Generally good agreement was achieved among the various approaches, but some differences were observed depending on the model context. The intercomparison work was challenging because of variable capabilities of the codes, and inspired some code enhancements to allow consistent comparison of flow and transport simulations across the full suite of methods. This study provides support for confidence in a variety of pore-scale modeling methods and motivates further development and application of pore-scale simulation methods. [ABSTRACT FROM AUTHOR]

Multiphase displacements in porous media are expected to be stable if the injectant has a smaller mobility than the resident phase and injection velocity is small. We investigate two-phase displacements (aqueous phase displacing oleic phase) at favorable mobility ratios, which are expected to be stable, and find that the presence of low-viscosity irreducible water promotes the formation of viscous instabilities. Microfluidic experiments and Lattice Boltzmann (LB) simulations were utilized to identify the effects of pore-scale mobilization of irreducible water on centimeter-scale flow patterns during favorable displacements. Displacements in glass micromodels showed the presence of low viscosity irreducible water resulted in fingering and early breakthrough compared to experiments with high viscosity irreducible water (glycerol solution). The LB simulations were used to explain that fingers formed because irreducible water was mobilized ahead of the injected water. The low viscosity aqueous front fingered through the oil as the viscosity of the oil was larger than that of the low viscosity aqueous phase bank. Additionally, we conducted a coreflood that showed breakthrough of the aqueous phase occurred slightly earlier when irreducible aqueous phase viscosity was low (1 cp) than when irreducible aqueous phase viscosity was large (69 cp). The novelty of this work lies in showing that presence of low viscosity irreducible water may result in an unstable displacement of medium viscosity oil by high viscosity aqueous solution at small flooding velocities. [ABSTRACT FROM AUTHOR]

• Novel fabrication methods are combined to make a core-scale micromodel for EOR. • Long micromodels capture core-scale physics such as the formation of oil banks. • Increasing viscosity of displacing phase in long micromodels increases the amount of oil recovered at breakthrough. Fluid injection experiments in rocks, commonly referred to as corefloods, are widely used to study and understand fluid flow in the subsurface. However, visual inspection of flow in cores requires computed tomography machines which may not be widely accessible. We introduce a novel micromodel that is as long as a typical core (40 cm), has adjustable pore structure, and includes 2.5D pore throats that can be used to conduct fluid displacements analogous to those in cores. Flow can be visualized inexpensively in the micromodel with an optical microscope. We performed standard coreflood tests in our micromodel including a tracer test and a steady state permeability test. We also conducted multiphase displacements by injecting aqueous solutions at varying glycerol concentrations to displace oil from the micromodel and observed the effect of the viscosity ratio on macro-scale recovery efficiency. When the injected aqueous solution was less viscous than the resident oil, it fingered through the oil. Fingering was not observed in the cases where the injected glycerol solution was more viscous than the oil. Moreover, as the viscosity of the injected glycerol solution increased, oil was recovered more rapidly. Additionally, we performed surfactant and glycerol floods in short (2.4 cm) and long (40 cm) micromodels that show long chips capture scale dependent physics, such as oil banking, that small chips do not capture. The novel micromodel shows promise as a screening tool for chemical EOR because it captures phase banks that are desirable in corefloods. [ABSTRACT FROM AUTHOR]