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Summary Polymer flooding is an enhanced oil recovery (EOR) method which improves the mobility ratio and sweep efficiency of a waterflood. In theory, the high viscosity of the polymer reduces its injectivity compared to water. However, field studies have documented much higher polymer injectivity than predicted by theoretical models. There are various reasons for high polymer injectivity. The objective of this work is to predict polymer injectivity in granular media accounting for fluid-induced fractures, water quality, polymer rheology, and undissolved polymers. We perform grain-scale, coupled fluid dynamics and granular mechanics modeling. Fluid-particle interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Simulation results show that polymer injection can create fractures in the granular media along the direction perpendicular to the minimum principal stress, thereby reducing wellbore pressure buildup at a constant polymer injection rate. The polymer tends to flow in the direction of fracture propagation in granular media, so the direction of the fracture affects the swept area of the polymer. Polymer rheology, water quality, and undissolved polymer also affect the polymer injectivity. Suspended solid particles may plug pores and reduce the injectivity of polymer by ~25%. Mechanically trapped undissolved polymers can greatly reduce polymer injectivity in low-permeability granular media. This work shows for the first time initiation of polymer-driven fractures in a granular model and demonstrates its implications on polymer injectivity.

Molecular models of the water–graphene interaction are essential to describe graphene in condensed phases.

This study presents a workflow to optimize the location of CO2 injectors in order to maximize stored volume and prevent fault reactivation due to increases of pore pressure. We combine coupled reservoir flow and geomechanics simulations with neural network surrogate models and find the best injector location based on net present environmental value (NPEV). The surrogate models can complement the numerical reservoir simulations and efficiently optimize the well location and injection rate via the steepest ascent algorithm. We apply the workflow to the Brugge field, a closed synthetic reservoir that incorporates multiple faults, as an example. The surrogate model predicts a NPEV of approximately 0.19 billion carbon credits for the Brugge field, which is consistent with the corresponding reservoir simulation. NPEV will change under different safety factors that serve as an additional injection control to enhance the safety of injection. This proposed workflow could be readily applied to other similar reservoir models.

Geological storage of carbon dioxide (CO2) in depleted gas reservoirs represents a cost-effective solution to mitigate global carbon emissions. The surface chemistry of the reservoir rock, pressure, temperature, and moisture content are critical factors that determine the CO2 adsorption capacity and storage mechanisms. Shale-gas reservoirs are good candidates for this application. However, the interactions of CO2 and organic content still need further investigation. The objectives of this paper are to (i) experimentally investigate the effect of pressure and temperature on the CO2 adsorption capacity of activated carbon, (ii) quantify the nanoscale interfacial interactions between CO2 and the activated carbon surface using Monte Carlo molecular modeling, and (iii) quantify the correlation between the adsorption isotherms of activated carbon-CO2 system and the actual carbon dioxide adsorption on shale-gas rock at different temperatures and geochemical conditions. Activated carbon is used as a proxy for kerogen. The objectives aim at obtaining a better understanding of the behavior of CO2 injection and storage into shale-gas formations. We performed experimental measurements and Grand Canonical Monte Carlo (GCMC) simulations of CO2 adsorption onto activated carbon. The experimental work involved measurements of the high-pressure adsorption capacity of activated carbon using pure CO2 gas. Subsequently, we performed a series of GCMC simulations to calculate CO2 adsorption capacity on activated carbon to validate the experimental results. The simulated activated carbon structure consists of graphite sheets with a distance between the sheets equal to the average actual pore size of the activated carbon sample. Adsorption isotherms were calculated and modeled for each temperature value at various pressures. The adsorption of CO2 on activated carbon is favorable from the energy and kinetic point of view. This is due to the presence of a wide micro to meso pore sizes that can accommodate a large amount of CO2 particles. The results of the experimental work show that excess adsorption results for gas mixtures lie in between the results for pure components. The simulation results agree with the experimental measurements. The strength of CO2 adsorption depends on both surface chemistry and pore size of activated carbon. Once strong adsorption sites within nanoscale network are established, gas adsorption even at very low pressure is governed by pore width rather than chemical composition. The outcomes of this paper provides new insights about the parameters affecting CO2 adsorption and storage in shale-gas reservoirs, which is critical for developing standalone representative models for CO2 adsorption on pure organic carbon.

Geometric straining of particles in porous media is of critical importance in a broad range of natural and industrial settings, such as contaminant transport in aquifers and the permeability decline due to pore plugging in oil reservoirs. Pore network modeling is a computationally efficient approach to simulate transport problems in porous media that has been used to simulate particle deposition and size exclusion. However, existing network models are unable to simulate particle jamming due to the simplification of geometry and the lack of capability for simulating particle–particle interactions. Here, we develop a novel pore network model for particle jamming in porous media. The jamming in pore throats is predicted by the probability of jamming, which is a function of pore/particle size ratio, particle concentration, and coefficient of friction (COF). A unified probability model is developed based on Discrete Element Method (DEM) simulations of particle jamming in porous media consisting of a single layer of spherical grains. The geometry is based on two packing extremes, those with grains arranged in a triangle and a square. The model is then implemented into the pore network model to predict jamming in porous media. This framework combines the efficiency of network modeling and the accuracy of direct simulations on particle jamming. We verify the model against CFD-DEM simulations. The results of network simulations show that the probability of jamming increases with COF. At low particle concentrations (C = 5%), the probability of jamming for large pore throats is small. There is a critical particle concentration (C = 9%) when the grain/particle size ratio is 10, above which jamming is self-reinforcing and the inlet face of the porous medium will be completely blocked (C = 11%). The effect of velocity on the probability of jamming is insignificant compared with the effects of particle concentration and pore/particle size ratio.

The injection of fluids into a compartmentalized formation induces pore pressure buildup and may result in reactivation of sealing faults. Among other variables, the pore volume compressibility (PVC) can affect the amount of pore pressure change during injection. PVC has been traditionally measured with isotropic loading compressibility tests. However, long and thin reservoirs subjected to depletion or injection typically follow a uniaxial strain stress path, rather than an isotropic stress path. Furthermore, injection unloads the reservoir rock by reducing effective stress, whereas depletion causes loading. This paper reports experimental measurements of the uniaxial strain unloading compressibility of Frio sand, a member of Tertiary strata in the Gulf of Mexico Basin. The uniaxial strain unloading compressibility increases nonlinearly from 0.29 to 1.45 GPa−1 (2 to 10 µsip) as the mean effective stress is reduced from 26 to 5 MPa. The uniaxial strain unloading compressibility of Frio sand is about one third of the uniaxial strain loading compressibility at comparable levels of effective stress. The uniaxial strain compressibility of Frio sand is roughly one half of the isotropic compressibility. Reservoir simulation highlights that using incorrect pore compressibility values considerably underestimates the expected increase of pore pressure in a compartmentalized formation during injection. Uniaxial strain unloading compressibility of target reservoir rocks should be accurately estimated or measured to prevent excessive pressure build up in target storage formations during injection of CO2 or any other fluid.

ABSTRACT: Fluid injection into sand may initiate fluid-driven fractures. The fluid-sand interaction patterns depend on the injection velocity, fluid viscosity, rheology and stress boundary conditions. However, the extension to non-Newtonian fluids and anisotropic stress conditions, such as in the case of injection of a polymer in the subsurface, is largely unexplored. In this paper, we study the injection of a Newtonian fluid (glycerol aqueous solution) and a shear-thinning fluid (scleroglucan) into a sand-filled Hele-Shaw cell. The experimental results demonstrate complex fracture patterns depending on injection velocity, fluid viscosity, boundary conditions and fluid rheology. The presence of stress-free boundaries causes the fracture opening to be almost perpendicular to the minimum principal stress. The peak injection pressure is also higher compared to the fixed-displacement boundaries. Compared to Newtonian fluid (glycerol), shear thinning polymer (scleroglucan) causes thinner fracture openings and more radial infiltration morphology in sand. The fracturing mechanism in sand is associated with the shear dilation at the tip of fractures and fracture offshoots. This study helps to clarify the basic flow and failure mechanisms of sand when subjected to injection of a non-Newtonian fluid. The insights obtained from these experiments can aid in the prediction of fracture morphology and sweep efficiency for on-site polymer injection. 1. INTRODUCTION Hydro-mechanical interactions between fluid flow and solids are common in many industries, such as oil and gas exploration, formation damage caused by particle jamming during oil and gas production (Li et al., 2021a), hydraulic fracturing (Zheng et al., 2020; Zheng and Sharma, 2021, Li et al., 2020), spray coating processes in food processing (Hilton et al., 2013) and tablet production in pharmaceuticals (Hemamanjushree and Tippavajhala, 2020). Different fluid infiltration and fracture opening morphologies caused by the injection of Newtonian fluids affect the fluid injectivity (Li et al., 2021b). However, extensions to non-Newtonian fluids and anisotropic stress conditions, such as in the case of injection of polymers in geological formations, are largely unexplored.

ABSTRACT: Thermal short-circuiting in Enhanced Geothermal Systems (EGS) is a reservoir-scale phenomenon, which arises from coupled thermal-hydraulic-mechanical feedback in response to heat drainage. Coupled feedback on the hydraulic aperture may increase fracture transmissivity drastically and decrease the production fluid temperature lowering the economically recoverable heat energy. This paper identifies the geometrical controls on short circuiting for multi-fracture enhanced geothermal systems to optimize the recoverable heat energy including: fracture spacing, number of parallel factures, wellbore diameter, injector-producer spacing, initial hydraulic aperture, hydraulic aperture distribution and thermo-hydro-mechanical fracture response. We use a combination of simple 1D hydraulic network simulations and fully coupled thermo-hydro-mechanical 3D models solved through FEM. Results show that thermal short-circuiting is more severe in formations (1) with initial or late high hydraulic apertures, in the order of tens of millimeters; (2) when fluid pressure exceeds the minimum total stress, causing large fracture re-opening; and (3) with a large number of fractures in a small rock volume, causing severe thermal and mechanical fracture interaction. Our modeling work suggests that thermal short-circuiting can be mitigated with an appropriate fracture design and operation. 1. INTRODUCTION Heat recovery in Enhanced Geothermal Systems (EGS) requires transmissive fractures connecting injection and production wellbores to increase hydraulic diffusivity of the surrounding rock (Brown et al., 1972; MIT, 2006; US Department of Energy, 2020). High surface area is desirable for large heat recovery because heat conduction in EGS reservoirs occurs at small rates (Fu et al., 2015; Gee et al., 2021). Yet, localized thermo-elastic contraction of the surrounding rock can increase fracture permeability and localize fluid flow, causing thermal short-circuiting (Armstead and Tester, 1986; Tsang and Neretnieks, 1998; Guo et al., 2016). Furthermore, fluid flow localization in EGS reservoirs can be caused by two processes: (1) fluid localization to preferred paths within a single fracture (flow-channeling) and (2) fluid localization to a few fractures within a hydraulic network of several fractures (plane-channeling). The latter is caused by distinct initial fracture geometries and viscous pressure loss between fractures (Shiozawa and McClure, 2014; Asai et al, 2018). These processes can form a thermal-hydraulic-mechanical (THM) coupled feedback loop because permeability increase within a single fracture tends to perturb the hydraulic network such that it accepts more working fluid. Hence, a coupled solution of fluid flow through wellbores and fractures with fluid flow and deformation of the surrounding rock is required to model the full transient behavior of multi-fracture EGS.

Summary The reduction of pore pressure caused by depletion can induce significant reservoir compaction and loss of permeability, especially in unconsolidated reservoirs. In this paper, we develop a numerical approach on the basis of computer-based simulations of unconsolidated rock samples subjected to mechanical tests that replicate the one-dimensional (1D) strain depletion path and allow for a prediction of permeability loss. The 1D strain stress path is a good approximation for long and thin conventional reservoirs with a compliant caprock. The numerical sample consists of crushable stiff and soft grains (proxies for sand and shale) simulated with the discrete element method (DEM) coupled with the bonded-particle model (BPM). Model parameters are calibrated through numerical single-grain-crushing tests which reproduce the experimentally measured sand strength. Grain crushing induced by the uniaxial strain stress path results in a pronounced reduction of porosity and permeability, which manifests more readily for samples with large grain size. The change of particle-size distribution indicates that high effective stresses cause grain crushing and production of a significant amount of fines that lower permeability. Simulation results indicate that the presence of soft grains and inclusions (e.g., shale fragments) facilitates grain crushing. Reservoir simulations—incorporating the change of porosity and permeability as a compaction table—show that the compaction can enhance cumulative production due to compaction drive but also reduces production rate by impairing the reservoir permeability. This multiscale numerical workflow bridges grain-scale compaction behavior and field-scale reservoir production.

Mechanical properties are essential for understanding natural and induced deformational behavior of geological formations. Brittleness characterizes energy dissipation rate and strain localization at failure. Brittleness has been investigated in hydrocarbon-bearing mudrocks in order to quantify the impact of hydraulic fracturing on the creation of complex fracture networks and surface area for reservoir drainage. Typical well logging correlations associate brittleness with carbonate content or dynamic elastic properties. However, an index of rock brittleness should involve actual rock failure and have a consistent method to quantify it. Here, we present a systematic method to quantify mudrock brittleness based on micro-mechanical measurements from the scratch test. Brittleness is formulated as the ratio of energy associated with brittle failure to the total energy required to perform a scratch. Soda lime glass and polycarbonate are used for comparison to identify failure in brittle and ductile mode and validate the developed method. Scratch testing results on mudrocks indicate that it is possible to use the recorded transverse force to estimate brittleness. Results show that tested samples rank as follows in increasing degree of brittleness: Woodford, Eagle Ford, Marcellus, Mancos, and Vaca Muerta. Eagle Ford samples show mixed ductile/brittle failure characteristics. There appears to be no definite correlation between micro-scratch brittleness and quartz or total carbonate content. Dolomite content shows a stronger correlation with brittleness than any other major mineral group. The scratch brittleness index correlates positively with increasing Young’s modulus and decreasing Poisson’s ratio, but shows deviations in rocks with distinct porosity and with stress-sensitive brittle/ductile behavior (Eagle Ford). The results of our study demonstrate that the micro-scratch test method can be used to investigate mudrock brittleness. The method is particularly useful for reservoir characterization methods that take advantage of drill cuttings or whenever large samples for triaxial testing or fracture mechanics testing cannot be recovered.

An uncommon facet of Formation Evaluation is the assessment of flow-related in situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow, i.e., saturation-dependent capillary pressure and relative permeability. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks and allows for the evaluation of effective two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasi-continuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. Experimental results indicate that flow patterns and in situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement is piston-like, as predicted by the Buckley-Leverett theory of fractional flow. Assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.

Fluid injection into porous media can initiate fluid-driven fractures. Unlike cohesive and homogeneous media, fluid-driven fractures in cohesionless granular media have complex fracture and leak-off morphologies. In this study, we investigate the mechanisms behind fluid-driven fractures in cohesionless granular media by coupling the discrete element method with computational fluid dynamics at the pore/grain scale. We perform numerical simulations of the injection of a fluid into a granular medium that is saturated with a second, immiscible fluid. Results show that fluid injection can initiate a fracture orthogonal to the minimum principal stress, as expected, through viscous drag forces. However, the displacement field around the fracture is much more complex than what is expected for a linear elastic solid, showing that (1) fracture propagation requires small leak-off (a few times the fracture width) and (2) localized shear deformation ahead of the fracture tip affects fracture morphology. The simulations support a transition from a leakoff-dominated fluid flow regime to a fracture-dominated regime, with the increase in characteristic time t1 (ratio of permeability and injection rate per unit length) and decrease in t2 (ratio of injected fluid viscosity and minimum total principal stress). We develop a correlation of the dimensionless initiation pressure PD,peak and dimensionless stress SD (upper bound: $$P_{D,peak} = 5.647S_{D}^{0.86}$$ , lower bound: $$P_{D,peak} = 0.567S_{D}^{0.83}$$ ) based on our grain-scale simulations, experimental data and field data from the literature, which can be used to predict the fracture initiation pressure in cohesionless granular media.

El objetivo de este trabajo es evidenciar la evolucion del gasto publico en salud, durante el periodo 1993-2017, para la poblacion no asegurada en el Estado de Sinaloa, Mexico. De esta forma se explora informacion de la economia de la salud que no ha sido investigada en esta entidad federativa. El presente estudio se basa en informacion desagregada, mediante la cual se hacen comparaciones de gasto publico en salud respecto al Producto interno bruto estatal (PIBE), gasto publico en salud respecto a gasto total y presupuesto del Fondo de Aportaciones para los Servicios de Salud (FASSA). Estos datos pueden ser utiles para los responsables de disenar las politicas publicas de salud en Sinaloa. La muestra fue no probabilistica, seleccionada en apego a los datos estadisticos y consulta de documentos que estuvieron disponibles. El hallazgo mas importante es la practica de reglas poco claras en la asignacion de recursos, por lo que se sugiere la implementacion de criterios transparentes en la distribucion del gasto que efectua la administracion publica estatal hacia las unidades medicas que tiene la Secretaria de Salud (SS) en el territorio de Sinaloa.

Fluid-driven open-mode fractures in porous media are the result of multiple physical processes governed by fluid properties, porous media properties, geometrical fracture properties, and fluid injection parameters. For example, a propagating open-mode fracture in which most work is spent on creating new fracture surface rather than on moving fluid through the fracture is said to be in a “toughness-dominated” regime. However, other multiphysical phenomena such as thermal dilation and mineral-dissolution can also affect fracture propagation. This study focuses on the facilitation of fracture propagation in toughness-dominated regime by weakening of the rock at the fracture tip by injection of a reactive fluid that causes mineral dissolution. We explore this coupled problem through numerical simulation using a finite element method (FEM) formulation based on the phase-field approach in order to solve equations for fluid flow, poroelasticity, linear elastic fracture mechanics and reactive transport. We couple mechanics and reactive fluid flow by assuming that fracture toughness decreases due to increases in rock porosity caused by mineral dissolution. The numerical simulation results show that acid injection and mineral dissolution (1) lower fracture breakdown pressure and (2) can bridge a transition from toughness-dominated to viscosity-dominated fracture propagation at constant injection pressure. Our results demonstrate that acid injection can change fracture propagation regimes and enable new phenomena that are not possible in unreactive porous media. The understanding of fracture propagation patterns and geometry manipulation is critical for safe and effective use of reactive fluids in the subsurface, such as in hydraulic fracturing, harnessing of deep geothermal energy, and carbon geological sequestration applications.

Open-mode fractures in sediments and rock occur both in natural processes and in engineering practice. In contrast to long planar fractures predicted by solutions in homogeneous media, laboratory and field observations often evidence complex and non-planar open-mode fracture networks in geological media. One cause of fracture complexity is the heterogeneity of material mechanical properties. This study focuses on the effects of mineral dissolution on pore structure modification in heterogeneous porous media and ensuing changes on fracture propagation characteristics. We performed semicircular bending experiments on limestone samples pre- and post-acidizing, mapped 3-D pore structure with X-ray microtomography, and used a finite element formulation based on the phase-field approach and linear elastic fracture mechanics to model initiation and propagation of open-mode fractures. Semicircular bending experiments on acidized carbonate rock samples show that non-planar fractures follow high porosity regions and large pores, and that fracture toughness correlates well with local porosity. Numerical modeling shows that a direct relationship between fracture toughness and porosity permits replicating fracture stress intensity at initiation and non-planar fracture propagation patterns observed in experiments. The results of this study indicate that mineral dissolution can affect fracture propagation patterns and that a coupling of mechanical and reactive processes in porous media formulations can be achieved through porosity and toughness. The understanding of fracture propagation patterns and geometry manipulation is critical for safe and effective use of reactive fluids in the subsurface, such as in hydraulic fracturing and carbon geological sequestration applications.

Geoethics is a term that describes the internal knowledge of values ​​which must be reflected in the interaction with other people and with the physical and biological environment that surrounds us.When talking about ethics or specifically geoethics, exact definitions are sought which always seem to be short and very difficult to write in a sentence. One of the reasons may be is that it is about minimizing a life process to a noun, adjective or adverb. "It is a life process," is an awareness of the maximum expression of that part that we call human, internal, which maintains a balanced posture. This self-awareness is essential since it allows to relate to the environment (including peers) in the same way, tolerant, dignified, respectful humanly and environmentally speakingIn 2020, during the pandemic, we have undertaken a challenge at our University by teaching a course on Geoethics in Earth Sciences (CITI199). This course was designed following the general guidelines of IAPG. The adaptation to the Chilean reality was given by the same students. After assimilating the bases of ethics, values ​​and moral principles, through the interventions of anthropologists, sociologists, geographers and native peoples, we have generated 2 unpublished activities in Chile, a student survey on the state of knowledge of geoethics in the School of Geology and applied the geoethical foundations in the daily life of Chile.In this series of presentations we report the results and analysis of the survey and recommendations to continue with the process of offering the university community the value of having an initial geoethical position in professional development. Later in the session, 4 situations in which society interacts with the environment from a geoethical perspective are evaluated and analyzed: 1) degradation and use of soils, 2) massive production of exotic salmon, 3) use of fresh water and 4 ) privatization of the common heritage of humanity in international waters.

Reservoir simulators often predict poor injectivity in polymer enhanced oil recovery (EOR) projects because of the high polymer viscosity, which is a deterrent for the project. However, field studies have shown much higher injectivity than predicted by the models. The objective of this work is to perform grain-scale, coupled fluid dynamics and geomechanics modeling to predict the injectivity of viscous, non-Newtonian polymers in wellbores. Fluid-rock interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Fluid flow is determined using an open-source CFD software that solves the volume-averaged Navier-Stokes equation using the finite volume method on Eulerian grids. Grain-scale geomechanics (DEM) is used to explicitly solve the particle trajectories in a Lagrangian reference system. The simulation results confirm the hypothesis of fracture initiation and sand failure near the injector. The results show that the polymer-driven fracture initiation is associated with sand shear failure, while the fracture geometry is the result of the localization of sand shear failure and fluidization of unconsolidated sand at the fracture tip. The injection of a viscous fluid can create fractures in the direction perpendicular to the applied minimum principal stress. The presence of fractures increases the injectivity. The peak injection pressure is more than 3 times greater than the applied minimum principal stress. The viscosity increase of polymers promotes the initiation of fractures and results in a greater fracture aperture. The injection of polymer can promote the initiation of fractures, and therefore, increase the polymer injectivity. This work, for the first time, uses a grain-scale model to predict polymer-driven fracture initiation and demonstrates the improved injectivity observed in the field.

El trabajo de investigación, fue realizado con la finalidad de correlacionar la promoción del empleo e inserción laboral de los jóvenes. A su vez, la hipótesis indica que hay una directa y significativa asociación entre las variables mencionadas. Se consideró como población y muestra a 103 emprendedores de las organizaciones juveniles. El tipo de investigación es aplicada, de enfoque cuantitativo y diseño descriptiva - correlacional. En los resultados se obtuvo que el 66% de emprendedores jóvenes opinan que los servicios recibidos son aceptables; sin embargo, el 55% tiene un nivel de inserción laboral baja. A nivel correlacional, hay una correlación poco significativa de 0.299 referente a las variables estudiadas, con una hay una asociación directa entre las variables de estudio. En sí, las dimensiones de la primera variable enmarcada en el PIP joven, como son la asociatividad, asistencia técnica y promoción comercial, se asocian directa y significativamente con a la segunda variable como es la inserción laboral de los jóvenes en San Martín.

Sedimentary rocks contain layers and a wide range of microstructures that may produce mechanical complexities including dynamic and quasistatic stiffness anisotropy and nonlinearity. However, most applications in geophysics and geomechanics disregard these mechanical complexities, which can lead to significant error and uncertainty in rock properties and may increase the risk associated with cost-intensive drilling and completions operations in shales. We have conducted simultaneous triaxial stress tests and ultrasonic wave propagation monitoring to measure and model stiffness anisotropy and nonlinearity of Mancos Shale plugs with varying bedding orientations. Results highlight the need for different sets of nonlinear coefficients to describe different stress loading paths, in which isotropic loading exhibits larger increases in stiffness for a given change in mean stress (and strain) than deviatoric loading. The vertical transverse isotropic (VTI) nonlinear model helps to account for the appreciable anisotropy and nonlinearity of Mancos samples, in which the dynamic Young’s moduli [Formula: see text] are more than 25% higher than [Formula: see text] and [Formula: see text] increases by approximately 35% during deviatoric stress loading. Measured static moduli are typically less than 50% of their dynamic equivalent and exhibit separate anisotropic and nonlinear relationships. Therefore, we have developed anisotropic stress-dependent dynamic-static transforms to estimate the static moduli from the nonlinear VTI model. Although heterogeneity and discontinuities cause samples to deviate from VTI symmetry, our modified dynamic-static transforms provide an excellent fit to the experimentally measured Young’s moduli and Poisson’s ratios. Post-test X-ray micro-CT imaging evidences the impact of sample layering and heterogeneity on rock failure and failure geometry. Bedding planes can act as preferential failure planes, whereas layering-induced mechanical stratigraphy can cause fractures to reorient due to changes in lithology. Our combined experimental, modeling, and imaging results provide insight into the complex deformational and failure behavior of shales. The analysis and results also highlight the need to consider the elastic and plastic deformations in shales.

Los inmuebles informales son un problema para sus usufructuarios, al no poseer titulos de propiedad. El objetivo de este articulo fue comprobar que en los municipios de Sinaloa, donde los padrones municipales de propiedades tienen una gran cantidad de inmuebles sin clasificar, se violan reglas institucionales al no poder gestionar titulos de propiedad que les permitan acreditarse como duenos, ademas de limitar la recaudacion de impuestos locales para las haciendas publicas municipales. La evidencia empirica demostro la existencia de un elevado porcentaje de inmuebles que no estan clasificados en el padron de contribuyentes y la potencialidad de contribuciones al suelo que no se estan aprovechando; se tiene una gran cantidad de terrenos informales, sin seguridad juridica para los contribuyentes, por lo que es necesario disenar un programa de politica publica local que mejore el desempeno de los catastros municipales de esta entidad federativa.

Depletion-induced formation compaction is a concern for production in hydrocarbon reservoirs. In this study, numerical mechanical tests and digital samples are proposed as an alternative to uniaxial strain experiments for investigating the effects of compaction. We propose a grain crushing model with two-sized subgrains based on the discrete element method and bonded-particle model (DEM-BPM) and perform numerical single grain crushing tests to calibrate the model parameters against the experimental sand grain characteristic strength. Numerical uniaxial strain tests are used to predict porosity and permeability reduction caused by reservoir compaction. Grain crushing incurs a significant reduction of porosity under the uniaxial strain stress path, which becomes more evident for digital samples consisting of larger grains. The stress-dependent changes in porosity and permeability obtained from the DEM simulations can be used as inputs for a reservoir-scale correlation to predict the productivity loss due to reservoir compaction.

This study integrates X-ray radiography and 3D computed tomography (CT) to measure xenon hydrate dissociation kinetics in a porous medium (sand) through depressurization at the quasi-isothermal condition. Before dissociation, we use X-ray CT to measure hydrate volume and surface area in the sand and find [hydrate volume]2/3 is a linear approximation of hydrate surface area regardless of differences in hydrate specific area. During dissociation, we use X-ray radiography to quantify the evolutions of hydrate volume and dissociation rate. We find [hydrate volume]2/3 (i.e., hydrate surface area) is a linear metric of hydrate dissociation rate. Additionally we observe two circumstances when dissociate rate is not linear with [hydrate volume]2/3. First, above a critical hydrate saturation of 35–45%, hydrate dissociation rate initially stays constant and then decreases with [volume]2/3. Second, the dissociation rates of patchy hydrates in large pores initially stay constant and are significantly slower than hydrates in small pores with the same sizes. Since methane hydrates in nature are patchy and heterogeneously distributed, the new knowledge will facilitate modeling of hydrates production with a simple metric of dissociation rate (i.e., [volume]2/3) and constraints of hydrate saturation and pore size.

CO2 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 CO2-charged brine on shear strength and stiffness of various outcrop rocks evaluated through triaxial testing. The tested rocks were exposed to CO2-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 CO2 leakage over time scales that exceed expected injection time scales (10–100 years). Results show mechanical alteration in various aspects: (1) CO2-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 CO2-charged brine can impart distinct petrophysical and geomechanical changes according to rock lithology and location with respect to major CO2 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.

Subsurface CO2 injection and storage alters formation pressure. Changes of pore pressure may result in fault reactivation and hydraulic fracturing if the pressure exceeds the corresponding thresholds. Most simulation models predict such thresholds utilizing relatively homogeneous reservoir rock models and do not account for CO2 dissolution in the brine phase to calculate pore pressure evolution. This study presents an estimation of reservoir capacity in terms of allowable injection volume and rate utilizing the Frio CO2 injection site in the coast of the Gulf of Mexico as a case study. The work includes laboratory core testing, well-logging data analyses, and reservoir numerical simulation. We built a fine-scale reservoir model of the Frio pilot test in our in-house reservoir simulator IPARS (Integrated Parallel Accurate Reservoir Simulator). We first performed history matching of the pressure transient data of the Frio pilot test, and then used this history-matched reservoir model to investigate the effect of the CO2 dissolution into brine and predict the implications of larger CO2 injection volumes. Our simulation results –including CO2 dissolution– exhibited 33% lower pressure build-up relative to the simulation excluding dissolution. Capillary heterogeneity helps spread the CO2 plume and facilitate early breakthrough. Formation expansivity helps alleviate pore pressure build-up. Simulation results suggest that the injection schedule adopted during the actual pilot test very likely did not affect the mechanical integrity of the storage complex. Fault reactivation requires injection volumes of at least about sixty times larger than the actual injected volume at the same injection rate. Hydraulic fracturing necessitates much larger injection rates than the ones used in the Frio pilot test. Tested rock samples exhibit ductile deformation at in-situ effective stresses. Hence, we do not expect an increase of fault permeability in the Frio sand even in the presence of fault reactivation.

Clathrate hydrate is a solid crystalline compound that consists of water cages with trapped gas molecules. Methane hydrate in permafrost and marine sediments is estimated to contain 2 × 103 to 4 × 106 Gt of carbon, which makes it both a potential energy source and a liability to global warming. The transport and mechanical properties of hydrate bearing sediments (HBS), and therefore hydrate dissociation through depressurization, thermal stimulation, or CO2 injection, depend on hydrate pore habit and spatial distribution in sediments. However, the evolution of hydrate pore habit and spatial distribution in HBS are not well understood yet. Here we show experimental evidence of Ostwald ripening of gas hydrate crystals in pores and porous media. We find that (1) hydrate growth rate (under nearly isothermal conditions) versus the degree of overpressurization fits an Arrhenius-type equation, and (2) Ostwald ripening gradually changes hydrate pore habit from grain-attaching to pore-filling and increases hydrate saturation heterogeneity at both pore and core scales. The latter ultimately creates significant spatial variations of permeability and sediment strength. Our results provide insights into kinetics and pore-scale physics that determine the geophysical signature from HBS at various scales. Based on our findings of hydrate occurrence in both gas and gas-water interface, we argue that hydrate growth in natural HBS is not limited to the water liquid phase. Our observation of hydrate pore habit alteration by Ostwald ripening explains patchy saturation and heterogeneous distribution of hydrate in natural HBS, which gives physical insight to improve geophysical hydrate models in porous media.

Organic shale reservoirs accommodate large amounts of hydrocarbons in extremely tight rock matrix. Slick water hydraulic fracturing and proppant placement is the most spread stimulating technology for this type of reservoirs. Some shale formations contain a fair amount of easily-dissolvable carbonates, which prompts shale acidizing as a potential method to increase reservoir permeability. Carbonates in shale formations can be present as a part of rock matrix or can be localized in natural fractures — so-called mineral veins. Previous studies investigated the effects of chemical dissolution within the matrix, implying that acidizing can etch the rock, open new conduits for flow, and increase fracture permeability after closure. This study rather focuses on the reservoir-scale geomechanical implications of chemical dissolution of mineral filling in natural fractures. We use a combination of elasto-plastic analytical methods, analogous thermo-elastic numerical solutions, and experimental results to elucidate the impact of veins dissolution on in-situ stresses. Analytical, numerical, and experimental results indicate that mineral dissolution of localized carbonate fractures leads to changes of local in-situ stresses. The direction of stress relaxation strongly depends on the orientation of mineralized fractures. Dissolution of near-vertical mineralized fractures contributes the most to decreases of effective horizontal stress and reduce stress shadow effects in multistage hydraulic fracture completions. Mineral dissolution, similar to pore pressure depletion or thermal cooling/heating, can increase stress anisotropy, which can reactivate critically-oriented natural fractures. In-situ stress chemical manipulation can be used advantageously to enlarge the stimulated reservoir volume.

The purpose of this article is to contribute to reflection on whether or not current policies exempting government-owned real estate from paying property tax are appropriate, from the perspective of Mexican municipal finance laws. This source of public revenue was given to Mexican municipalities in February 1983, so for the past 34 years it has been and remains an unfulfilled promise in terms of tax collection. A number of studies have been published on the economic determinants of property tax in Mexico, but exemptions from this tax have not been studied from a regulatory standpoint; this issue is still unexplored and unaddressed by experts in the field. This paper seeks to answer the following questions: What are the municipal finance laws regarding exemptions of government real estate from property tax? How do property tax exemptions for government real estate limit municipal revenue potential? What other factors have contributed to limiting the revenues generated by this tax?

Geologic carbon sequestration in deep saline aquifers results in a low pH brine plume that pushes into subsurface storage reservoirs and can access pre-existing or induced microfractures. This work investigates the effect of acidic brine on displacement of an artificial fracture under stress in the dolomite- and clay-cemented Bandera Gray sandstone. Samples were held under stress in a custom flow cell housed within an industrial CT scanner, and either acidic (pH 4) or reservoir-simulated (pH 8.3) brine was flowed through the artificial fracture for seven days. CT imaging shows that acidic brine resulted in greater shear slip than reservoir-simulated brine, with 0.379 ± 0.022 mm shear slip after pH 4 flow and only 0.213 ± 0.011 mm slip after pH 8.3 flow. Fracture surfaces exposed to acidic brine had rougher surfaces and lower fracture toughness, respectively, than those exposed to reservoir-simulated brine. SEM images of fracture surfaces indicate a loss by area of Fe-dolomite cementing crystals (6.05 ± 1.37% to 3.78 ± 0.73%) after exposure with the acidic brine, as well as a corresponding porosity increase (24.6 ± 1.1% to 26.1 ± 1.1%). These results indicate dissolution and weakening of the dolomite cements by acidic brine frees individual grains at the fracture surface to move, resulting in geochemically-induced stress release. Acidic brine created from geological carbon sequestration can dissolve sandstone cements and lead to increased shear slip at fracture interfaces, but further work at larger scales and with more realistic fracture conditions is needed.

Microfracturing and induced elastic anisotropy impart changes on body wave velocities with implications to seismic and wellbore testing methods and interpretation. We have conducted simultaneous triaxial stress tests and ultrasonic wave propagation monitoring to quantify S-wave anisotropy and microfracture development in Berea Sandstone and Silurian Dolomite. The onset of stress-induced microfracturing is detected at the beginning of appreciable S-wave anisotropy called the “S-wave crossover” (SWX). The SWX and subsequent increases in S-wave anisotropy evidence microstructural damage development well before quasistatic indicators such as the volumetric strain point of positive dilatancy (PPD) and yield/failure in all samples. X-ray microtomography confirmed fracture development and allowed for geometric assessment of fracture orientation. Stresses at the SWX and PPD are compared with peak axial stress to understand linkages between damage and ultimate rock strength. In Berea Sandstone, the SWX occurs at 40%–60% of the peak axial stress, whereas in Silurian Dolomite, SWX occurs at approximately 60%–80% of the peak axial stress. Results indicate that rock samples undergo irreversible microstructural changes before dilatancy manifests, and earlier than previously thought. Analysis of tangent elastic coefficients indicates that the ratio between the dynamic and static Young’s moduli can change significantly prior to SWX due to elastic and inelastic processes induced by deviatoric loading and ranges from approximately 2:1 to 4:1 for Berea and 2:1 to 7:1 for Silurian. Understanding damage development and the relationship between the dynamic and static responses of rocks provides opportunities to upscale stress-strain behavior to the wellbore environment and for improved geomechanical interpretation from dipole sonic and time-lapse well-log analyses.

Accurate geomechanical evaluation of oil and gas reservoir rocks is important to provide design parameters for drilling, completion and predict production rates. In particular, shale reservoir rocks are geologically complex and heterogeneous. Wells need to be hydraulically fractured for stimulation and, in complex tectonic environments, it is to consider that rock fabric and in situ stress, strongly influence fracture propagation geometry. This article presents a combined wellbore-laboratory characterization of the geomechanical properties of a well in El Trapial/Curamched Field, over the Vaca Muerta Formation, located in the Neuquen Basin in Argentina. The study shows the results of triaxial tests with acoustic measurements in rock plugs from outcrops and field cores, and corresponding dynamic to static correlations considering various elastic models. The models, with increasing complexity, include the Isotropic Elastic Model (IEM), the Anisotropic Elastic Model (AEM) and the Detailed Anisotropic Elastic Model (DAEM). Each model shows advantages over the others. An IEM offers a quick overview, being easy to run without much detailed data for heterogeneous and anisotropic rocks. The DAEM requires significant amounts of data, time and a multidisciplinary team to arrive to a detailed model. Finally, an AEM suits well to an anisotropic and realistic rock without the need of massive amounts of data.

Small pores in high specific surface clay-rich caprocks give rise to high capillary entry pressures and high viscous drag that hinder the migration of buoyant carbon dioxide CO2. We measured the breakthrough pressure and ensuing CO2 permeability through sediment plugs prepared with sand, silt, kaolinite and smectite, and monitored their volumetric deformation using high-pressure oedometer cells. The data show water expulsion and volumetric contraction prior to CO2 breakthrough, followed by preferential CO2 flow thereafter. Our experimental results and data gathered from previous studies highlight the inverse relationship between breakthrough pressure and pore size, as anticipated by Laplace’s equation. In terms of macro-scale parameters, the breakthrough pressure increases as the sediment specific surface increases and the porosity decreases. The breakthrough pressure is usually lower than the values predicted with average pore size estimations; it can reach ∼6.2 MPa in argillaceous formations, and 11.2 MPa in evaporites. The CO2 permeability after breakthrough is significantly lower than the absolute permeability, but it may increase in time due to water displacement and desiccation. Leakage will be advection-controlled once percolation takes place at most storage sites currently being considered. Diffusive and advective CO2 leaks through non-fractured caprocks will be minor and will not compromise the storage capacity at CO2 injection sites. The “sealing number” and the “stability number” combine the initial fluid pressure, the buoyant pressure caused by the CO2 plume, the capillary breakthrough pressure of the caprock, and the stress conditions at the reservoir depth; these two numbers provide a rapid assessment of potential storage sites. Unexpected CO2 migration patterns emerge due to the inherent spatial variability and structural discontinuities in geological formations; sites with redundant seal layers should be sought for the safe and long-term storage of CO2.

The geologic sequestration of CO2 is a potential solution for decreasing anthropogenic atmospheric CO2 emissions by trapping it underground. A primary mechanism for storage is structural trapping where low permeability and high capillary entry pressure caprock materials hold back the buoyant CO2 from rising to the surface. The wettability (or contact angle) of reservoir and caprock materials in relation to CO2 and formation brine partly determines the efficiency of structural trapping. Current practice applies the results of individual reservoir-comprising minerals recorded under laboratory conditions, to rocks under in-situ reservoir conditions. However, the wide variety of measured contact angles reported in the literature calls this practice into question. Moreover, organic shales have not been the focus of systematic studies. Here we analyzed the wettability of CO2 on organic shales at various organic matter concentrations and thermal maturities. We found that bulk organic shale remains highly water wet with respect to CO2 despite changes to the maturity or concentration of organics. This finding is in contrast to recent molecular dynamic simulations and our initial expectations from previous pore-scale analyses in which organic matter was shown to be hydrophobic. The results are likely due to the remaining mineralogy of the rock dominating the wetting behavior despite concentrations of organics up to 7.9%. This means that reservoirs and aquifers capped by organic rich caprocks may be suitable locations for CO2 storage and that organic matter at concentrations below percolation threshold may not have a detrimental effect on structural trapping efficiency.