Permeability Contrast Research Articles

Fluctuating hydrodynamics of an autophoretic particle near a permeable interface

We study the autophoretic motion of a spherical active particle interacting chemically and hydrodynamically with its fluctuating environment in the limit of rapid diffusion and slow viscous flow. Then, the chemical and hydrodynamic fields can be expressed in terms of integrals. The resulting boundary-domain integral equations provide a direct way of obtaining the traction on the particle, requiring the solution of linear integral equations. An exact solution for the chemical and hydrodynamic problems is obtained for a particle in an unbounded domain. For motion near boundaries, we provide corrections to the unbounded solutions in terms of chemical and hydrodynamic Green's functions, preserving the dissipative nature of autophoresis in a viscous fluid for all physical configurations. Using this, we give the fully stochastic update equations for the Brownian trajectory of an autophoretic particle in a complex environment. First, we analyse the Brownian dynamics of particles capable of complex motion in the bulk. We then introduce a chemically permeable planar surface of two immiscible liquids in the vicinity of the particle and provide explicit solutions to the chemo-hydrodynamics of this system. Finally, we study the case of an isotropically phoretic particle hovering above an interface as a function of interfacial solute permeability and viscosity contrast.

Spontaneous Imbibition in Dual Permeable Media Using Dynamic Pore Network Model

AbstractUnderstanding preferential flow in porous media holds substantial theoretical significance on the design and optimization of hydrocarbon exploitation in shale reservoir. Previous researches discussed the competition of imbibition front in layered porous media while the underlining mechanism for interfacial dynamics and induced displacement efficiency of multiphase flow remains ambiguous. In this paper, we investigate the spontaneous imbibition in dual permeable media and analyze the flux exchange between the neighboring porous zones with permeability contrast using dynamic pore network model. The impact of fluid viscosity ratio and permeability contrast on the spontaneous imbibition preference have been addressed, and finally a phase diagram for displacement efficiency has been obtained. The results reveal that the dual permeable structure enhances the invasion rate of wetting fluid in the low‐permeable zone and induces unstable displacement patterns, leading to reduction of the long‐term displacement efficiency. The interfacial pattern transition from stable displacement to unstable pattern in dual permeable media could be ascribed into the flux exchange between dual permeable zones, which shows a contrary impact on the fluid flow within the low‐permeable zone under favorable and unfavorable viscosity ratios. The permeability contrast in dual permeable media intensifies this impact during spontaneous imbibition. These results help us to understand the occurrence and mutual interaction of multiphase flow in layered porous media, and provide a theoretical guidance for the hydrocarbon exploitation in shale reservoir.

Analysis of Inter-Layer Interference in Multi-Layer Reservoir Commingled Production Wells

During the operation of commingled production wells, inter-layer interference is a key factor affecting the recovery rate and flooding extraction efficiency. This study proposes a well deliverability equation that is characterized by a multi-parameter coupled inter-layer interference coefficient, which is applied to quantify the commingled production wells in a multi-layer reservoir. This study used principal component analysis (PCA) to study the combined effects of correlation parameters for inter-layer interference. The results show that the starting pressure gradient and the crude oil viscosity contrast have the most significant impact on inter-layer interference. Changes in these two parameters directly enhance the heterogeneity between different oil layers, thereby intensifying inter-layer interference. Additionally, the positive correlation between permeability and permeability contrast also highlights the contribution of physical property differences in the oil layers to the interference. The sensitivity analysis shows the main influencing factors of inter-layer interference in commingled production wells. providing references for subsequent improvements and optimization of the exploitation schemes and adjustments in reservoir management measures. The results not only enhance the understanding of the mechanisms of inter-layer interference in the exploitation of multi-layer oil reservoirs but also provide scientific evidence and technical support for oilfield development.

Experimental Study on Factors Affecting Oil Recovery in Sandstone-Buried Hill Superimposed Reservoirs.

Sandstone-buried hill superimposed reservoirs, characterized by the coexistence of the sandstone matrix and the fracture pore matrix, present unique challenges in integrated development due to their connectivity and physical properties. Currently, research on the factors affecting the recovery of sandstone-buried hill superimposed reservoirs with both porous and fractured media is limited. In this study, a more realistic method for preparing fractured cores and calculating fracture permeability was proposed, and the effect of confining pressure on fracture permeability was investigated. Additionally, a three-tube experimental apparatus was designed to study the effects of connectivity, different permeability contrasts between sandstone and buried hills, and various development strategies on recovery. The results indicate that fracture permeability is significantly affected by the confining pressure. When sandstone and buried hills are not connected, the total recovery is the highest. As connectivity increases, the recovery from sandstone gradually decreases, while the recovery from the buried hill gradually increases, leading to a decrease in the overall recovery. The permeability contrast between sandstone and buried hill has a minimal impact on the overall recovery; however, a higher permeability contrast leads to increased sandstone recovery and decreased buried hill recovery. The highest overall recovery was achieved with injection solely into the sandstone, followed by general injection, with the lowest recovery from injection solely into the buried hill. This study provides new insights into the integrated development of sandstone-buried hill reservoirs.

The effect of matrix-fracture permeability contrast on hydrocarbon foam performance in oil-wet carbonate

The effect of matrix-fracture permeability contrast on hydrocarbon foam performance in oil-wet carbonate

Evaluation method of sandy conglomerate reservoir heterogeneity based on the combined weighted TOPSIS model

At present, single parameters for characterizing reservoir heterogeneity are commonly used in oilfield exploration and development, such as the permeability coefficient of variation, permeability inrush coefficient, and extreme difference, which have problems such as characterization blind spots. The heterogeneity of thick-bedded sand and conglomerate reservoirs is affected by various factors due to their thick layer characteristics, and it is difficult to effectively evaluate the heterogeneity of thick-bedded sand and conglomerate reservoirs with a single parameter. According to the characteristics of the thick sandy conglomerate reservoir, a comprehensive index calculation method of heterogeneity based on the combination weighting TOPSIS evaluation model is developed to comprehensively evaluate the heterogeneity of the sandy conglomerate reservoir by synthesizing the parameters affecting the heterogeneity of the reservoir, such as porosity, permeability, thickness of the sand layer, effective thickness coefficient, permeability variation coefficient, permeability rush coefficient, permeability contrast, and mudstone content. This approach is conducive to the normalized evaluation of complex reservoirs, and the quantitative characterization is more accurate and comprehensive. Based on the former classification scheme and the geologic characteristics of the study area, the evaluation criteria of the heterogeneity of the sandstone conglomerate reservoir are determined according to the comprehensive heterogeneity index. The research indicates that the objective weights of each indicator parameter of reservoir heterogeneity can be reasonably calculated by improving the criteria importance though intercrieria correlation weighting method, and the combined weights reflecting the importance of the indicators can be obtained by modifying the objective weights through the analytic hierarchy process. The calculated heterogeneous comprehensive index can be used to quantitatively characterize the heterogeneity of sand conglomerate reservoirs and solve the problems existing in conventional single parameters. The heterogeneous synthetic index has a good correlation with conventional parameters and has a good positive correlation with productivity. The weaker the heterogeneity is, the higher the productivity.

Impact of Pressure-Dependent Interfacial Tension and Contact Angle on Capillary Heterogeneity Trapping of CO2 in Storage Aquifers

Summary Carbon dioxide (CO2) capillary trapping increases the total amount of CO2 that can be effectively immobilized in storage aquifers. This trapping, manifesting itself as accumulated CO2 columns at a continuum scale, is because of capillary threshold effects that occur below low-permeability barriers. Considering that capillary pressure is dictated by heterogeneous pore throat size, the trapped CO2 column height and associated CO2 saturation will vary spatially within a storage aquifer. This variation will be influenced by two pressure-dependent interfacial parameters—CO2/brine interfacial tension (IFT) and CO2/brine/rock contact angle. Our objective is to understand how the pressure dependence of these two parameters affects the heterogeneity of capillary trapped CO2 at a continuum scale. Our conceptual model is a 1D two-zone system with the upper zone being a flow barrier (low permeability) and the lower zone being a flow path (high permeability). The inputs to this model include microfacies-dependent capillary pressure vs. saturation curves and permeability values. The input capillary pressure curves were collected in the literature that represents carbonate microfacies (e.g., dolograinstone) in a prevalent formation in the Permian Basin. We then used the Leverett j-function to scale the capillary pressure curve for the two zones that are assigned with the same or different microfacies. During scaling, we considered the influence of pressure on both the IFT and contact angle of CO2/brine/dolomite systems. We varied the zone permeability contrast ratio from 2 to 50. We then assumed capillary gravity equilibriums and calculated the CO2 saturation buildup corresponding to various trapped CO2 column heights. The CO2 saturation buildup is defined as the CO2 saturation in the lower layer minus that in the upper one. We found that the saturation buildup can be doubled when varying pressure in a storage aquifer, after considering pressure-dependent IFT and contact angles. Thus, assuming these two parameters to be constant across such aquifers would cause large errors in the quantification of capillary trapping of CO2. The whole study demonstrates the importance of considering pressure-dependent interfacial properties in predicting the vertical distribution of capillary trapped CO2. It has important implications in developing a better understanding of leakage risks and consequent storage safety.

Nanoparticle-stabilized CO2 foam flooding for enhanced heavy oil recovery: A micro-optical analysis

Surfactant flooding is a well-known chemical approach for enhancing oil recovery. Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions. Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO2 co-injection because they generate stable foam, reduce the interfacial tension (IFT) between water and oil, cause emulsions to spontaneously form, change the wettability of porous media, and change the characteristics of flow. In the current work, the simultaneous injection of SiO2, Al2O3 nanoparticles, anionic surfactant SDS, and CO2 in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery. IFT (interfacial tension) was reduced by 44% when the nanoparticles and SDS (2000 ppm) were added, compared to a reduction of roughly 57% with SDS only. SDS-stabilized CO2 foam flooding, however, is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil. To assess foam's potential to shift CO2 from the high permeability zone (the thief zone) into the low permeability zone, directly visualizing micromodel flooding was successfully executed (upswept oil-rich zone). Based on typical reservoir permeability fluctuations, the permeability contrast (defined as the ratio of high permeability to low permeability) for the micromodel flooding was selected. However, the results of the experiment demonstrated that by utilizing SDS and nanoparticles, minimal IFT was reached. The addition of nanoparticles to surfactant solutions, however, greatly boosted oil recovery, according to the findings of flooding studies. The ultimate oil recovery was generally improved more by the anionic surfactant (SDS) solution including nanoparticles than by the anionic surfactant (SDS) alone.

Numerical Simulations of Viscous Fingering in Fractured Porous Media

AbstractThe effect of heterogeneity induced by highly permeable fracture networks on viscous miscible fingering in porous media is examined using high-resolution numerical simulations. We consider the planar injection of a less viscous fluid into a two-dimensional fractured porous medium that is saturated with a more viscous fluid. This problem contains two sets of fundamentally different preferential flow regimes; the first is caused by the viscous fingering, and the second is due to the permeability contrasts between the fractures and the rock matrix. We study the transition from the regime where the flow is dominated by the viscous instabilities, to the regime where the heterogeneity induced by the fractures define the flow paths. Our findings reveal that even minor permeability differences between the rock matrix and fractures significantly influence the behavior of viscous fingering. The interplay between the viscosity contrast and permeability contrast leads to the preferential channeling of the less viscous fluid through the fractures. Consequently, this channeling process stabilizes the displacement front within the rock matrix, ultimately suppressing the occurrence of viscous fingering, particularly for higher permeability contrasts. We explore three fracture geometries: two structured and one random configuration and identify a complex interaction between these geometries and the development of unstable flow. While we find that the most important factor determining the effect of the fracture network is the ratio of fluid volume flowing through the fractures and the rock matrix, the exact point for the cross-over regime is dependent on the geometry of the fracture network.

Molecular dynamics simulation and key performance study of VES self-diverting acid system for deep carbonate reservoirs

Viscoelastic Surfactant (VES) self-diverting acid technology is an ideal approach for enhanced recovery from heterogeneous reservoirs. Most VES self-diverting acid systems currently used in field operations are only suitable for low-temperature reservoirs, and research on self-diverting VES acid systems for deep carbonate rock formations is lacking. Additionally, studies on the molecular dynamics of the self-assembly of VES have mainly focused on cationic surfactants, with insufficient research on the self-assembly of betaines in the oil industry. This study investigated the effects of temperature, surfactant concentration, and metal ion concentration on the self-assembly of erucamide propyl hydroxysulfobetaine (EHSB) based on a self-assembly model through molecular simulation methods. Moreover, the viscosity of the EHSB was predicted under various conditions. The results indicated that the system viscosity was optimal at an EHSB concentration of 4 wt%. The EHSB system requires initiation by metal ions to enhance the viscosity, with Ca2+ having a more pronounced effect than Mg2+. This is attributed to the formation of a unique “octahedral” structure by Ca2+ in solution, which aids in the formation of large micelles. Furthermore, because of the smaller ionic radius of Mg2+ compared with that of Ca2+, Mg2+ is more likely to penetrate micelles and form salt bridges, promoting a tighter arrangement of surfactant molecules. Based on molecular simulation and laboratory experiments, under optimal concentrations of inorganic salts and EHSB, the system’s viscosity remained greater than 150 mPa·s at 140 °C, meeting the requirements for diversion in deep carbonate rock formations. Finally, the acidization capacity and diversion effects of the acidic system were demonstrated using single-core flood and dual-core diversion experiments. The results showed that the acid solution significantly etched the core, and the residual acid reduced the permeability contrast of the core from 3.54 to 2.35, indicating a good acidizing diversion performance. This study utilizes a combination of computer simulations and laboratory experiments to optimize a VES self-diverting acid system. The computer-predicted viscosity corresponds well with the actual measured viscosity, providing new technical insights for evaluating the performance of VES under complex formation conditions that are unattainable through laboratory tests. A self-diverting VES acid system suitable for deep carbonate rock reservoirs at 140 °C was developed, providing technical support for the efficient development of deep carbonate reservoirs.

Hybrid Technology Incorporated Into Colombian Heavy Oil Field Development Plan

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213199, “Incorporating Hybrid Technology of CSS and Foam in Heavy Oil Field Development Plans: Practical Experiences and Lessons Learned,” by Romel A. Perez, SPE, Hector A. Rodriguez, and Jorge E. Romero, Ecopetrol, et al. The paper has not been peer reviewed. _ A research and development project was conducted to study the use of preformed foams to improve cyclic steam stimulation (CSS). The field results showed benefits in incremental oil production, improvements in energy efficiency, and reduction in carbon intensity. Based on those outcomes, and with the goal of extending the production life of mature assets, the hybrid technology of CSS plus foam improvements was incorporated into the heavy oil field development plans of the Middle Magdalena Valley (MMV) basin in Colombia. Pilot Results: 2019–2022 CSS maturity is one of the major challenges in the MMV. Many wells report more than 10 steam cycles, decreasing oil productivity, and a trend of shorter steam cycles (less than 10 months). Most injected steam drained the higher-flow-capacity intervals based on the permeability contrast within the pay zone and openhole completions. Therefore, the bullhead injection of preformed foam improvements implemented before the steam cycle was proposed as part of a conformance strategy. The main goal of the pilot test was to demonstrate the efficiency of the hybrid technology, extend the production life of steam cycles, increase oil recovery, and improve energy efficiency and carbon footprint. The CSS pilot was implemented in six wells of the Teca-Cocorna field (Fig. 1). Performance was evaluated in terms of incremental oil, carbon intensity, and energy efficiency. A similar approach was proposed to evaluate energy efficiency and greenhouse emissions of CSS and hybrid CSS based on numerical simulations and the performance of two wells in Block D-80 in China. By the end of this stage, an incremental oil of approximately 32,000 STB was confirmed. Only one well recorded almost 50% of the total incremental oil of the pilot, and one well was only evaluated for 6 months because of a mechanical failure. Incremental oil recoveries and geochemical analysis confirmed the potential of this hybrid steam method to target unswept zones in idle or marginal wells operating since the 1980s. Additionally, the Teca-Cocorna pilot reduced carbon intensity and improved energy efficiency by 56% and 54%, respectively. The reduction of the carbon intensity from 83 (baseline) to 46 kg CO2/STB represents an important achievement in terms of environmental benefits and highlights the fact that the volume of natural gas used to generate steam was optimized by using less gas by extending steam cycles to a minimum of 9 months. In other words, the CCS/foam cycle can produce as much oil as two CCS cycles in the pilot wells.

Anomalous Pressure Diffusion and Deformation in Two‐ and Three‐Dimensional Heterogeneous Fractured Media

AbstractIn fractured and stress‐sensitive reservoirs and aquifers, hydromechanical coupling is important, in connection with their heat and solute transport properties, and because the fluid production or extraction leads to land subsidence and potentially to induced seismicity. Classical dual‐porosity poroelasticity (DPP) models cannot upscale pressure diffusion and deformation in fractured porous media, which are characterized by anomalous behaviors that manifest in strong tailing in the temporal evolution of flow rate and subsidence. We study these behaviors using detailed numerical simulations of fluid production in naturally fractured formations characterized by multi‐Gaussian distributions of the matrix permeability. We find that the tailing behaviors depend on the permeability contrast between fracture and matrix, on the permeability distribution in the matrix, and on the correlation length. We use a non–equilibrium, multi‐porosity model to quantify the coupled behaviors of anomalous pressure diffusion, fluid flow and deformation. The model is parameterized by medium and fluid properties, which set the characteristic pressure diffusion time scales. It allows to identify the emerging scaling regimes and scaling behaviors of flow rate and subsidence. We propose a model implementation that captures the full anomalous evolution of flow rates and displacements observed in the detailed numerical simulations in terms of the permeability distribution and matrix length scales. The presented results shed new light on the controls of medium heterogeneity and geometry on pressure diffusion, fluid production and subsidence in highly heterogeneous fractured media.

Investigation of CO2-EOR and storage mechanism in Injection-Production coupling technology considering reservoir heterogeneity

Heterogeneous reservoirs offer greater potential for increased oil production and carbon storage capacity when using CO2 injection-production coupling technology in a broader range of geological formations. However, the impact of heterogeneity on the mechanisms and effectiveness of CO2 utilization and storage remains unclear. This study comprehensively investigates the mechanisms of enhanced oil recovery and the sequestration potential of CO2 injection-production coupling technology in heterogeneous reservoirs using both microscopic visualization experiments and macroscopic core experiments. The results reveal that during continuous gas flooding, CO2 forms rapid flow channels, leading to the formation of oil films and columnar residual oil in high-permeability zones, while small pores remain unaffected. Meanwhile, under high-speed injection conditions, the overall microscopic recovery rate increases by 13.8%. However, a higher proportion of porous residual oil is retained in low-permeability zones. During asynchronous injection-production cycles, the microscopic recovery rate remains above 86%, indicating a more thorough utilization of porous residual oil, which is predominantly present in membranous and angular corner configurations. The mechanisms of enhanced oil recovery include the increase in energy, dissolution expansion, and displacement-transport mechanisms. In asynchronous injection-production mode, macroscopic recovery rates are all above 80%. Additionally, with an increase in permeability contrast, the CO2 utilization efficiency rises from 5.9% to 8.6%, demonstrating the high potential of injection-production coupling technology for enhanced oil recovery and geological carbon sequestration in heterogeneous reservoirs. This study provides theoretical support for CO2 injection development and geological sequestration in heterogeneous reservoirs.

Physics-informed shape optimization using coordinate projection

The rapid growth of artificial intelligence is revolutionizing classical engineering society, offering novel approaches to material and structural design and analysis. Among various scientific machine learning techniques, physics-informed neural network (PINN) has been one of the most researched subjects, for its ability to incorporate physics prior knowledge into model training. However, the intrinsic continuity requirement of PINN demands the adoption of domain decomposition when multiple materials with distinct properties exist. This greatly complicates the gradient computation of design features, restricting the application of PINN to structural shape optimization. To address this, we present a novel framework that employs neural network coordinate projection for shape optimization within PINN. This technique allows for direct mapping from a standard shape to its optimal counterpart, optimizing the design objective without the need for traditional transition functions or the definition of intermediate material properties. Our method demonstrates a high degree of adaptability, allowing the incorporation of diverse constraints and objectives directly as training penalties. The proposed approach is tested on magnetostatic problems for iron core shape optimization, a scenario typically plagued by the high permeability contrast between materials. Validation with finite-element analysis confirms the accuracy and efficiency of our approach. The results highlight the framework’s capability as a viable tool for shape optimization in complex material design tasks.

Surface-derived fluid percolation along detachment systems enhanced by syn-kinematic granites: uranium mineralization as an application

Detachment zones are privileged areas for the interaction between surface-derived fluids and rocks, potentially leading to ore deposition. However, the hydrodynamics of detachments and specifically the way by which surface-derived fluids reach crustal depths, remain enigmatic. This question is even more puzzling when the heating caused by the emplacement of a syn-kinematic granite increases the buoyancy of fluids, thus impeding their descent. Here, 2D hydrothermal numerical models are performed. The geometry comprises a detachment and secondary normal faults in the hanging wall. Sensitivity tests were carried out to assess the impact of topographic gradients, syn-tectonic magmatic activity and the depth-dependent permeability contrast between the detachment and the crust. Several flow indicators, integrated over time and combined with particle tracking, enable us to highlight the main controls of fluid circulations. Our study reveals that the infiltration of surface-derived fluids into detachment zones is enhanced by the presence of a heat source at depth, such as a syn-kinematic pluton. Secondary faults are the main percolation path for surface-derived fluids infiltrating the detachment. Plume-like thermal anomalies have been spotted between these faults. The dynamic permeabilities of magmatic intrusions, which depend on sub-solidus temperatures, spatially and temporally reproduce the conceptual model of uranium mineralization in the South Armorican Variscan Domain, which is used as an example.

Numerical simulation of the effects of the fault dip angle and permeability contrast on heat transfer and Fluid flow in Geothermal sites

Jeotermal sahalarda fayların/kırıkların varlığı, jeotermal akışkanın ve sıcaklığın dağılımını önemli ölçüde etkilemektedir. Özellikle yoğun faylanmanın olduğu sahalarda bu etki daha fazla ön plana çıkmaktadır. Daha önceki çalışmalar, fayların varlığının ve fay ile ortam arasındaki permeabilite farkının, akışkan hareketi üzerine olan etkilerini tartışmıştır. Bu etkinin anlaşılabilmesi için seçilebilecek yöntemlerin başında, pek çok fiziksel ve hidrolik parametreyi kapsayan sayısal modelleme çalışmaları gelmektedir. Bu çalışmada, fayların eğimlerinin ve fay-civar kayaçlar arası permeabilite kontrastının neden olduğu sıcaklık dağılımı ve yeraltısuyu akış dağılımı farklı test modeller oluşturularak incelenmiştir. Sayısal modelleme için Hesaplamalı Akışkanlar Dinamiği (HAD) programı olan ve sonlu hacimler prensibi ile çalışan ANSYS Fluent yazılımı kullanılmıştır. Test modellerinin sonuçları, fay açısı değişiminin, sıcaklık dağılımını ve hız vektörlerinin yönünü bir miktar etkilese de, esas belirleyici faktörün permeabilite kontrastı olduğunu göstermektedir. Bu çalışma, yoğun faylanmanın olduğu jeotermal sahalarda, akışkanın olası yollarını kestirebilmek için bir ön çalışma olarak uygulanabilir ve geliştirilebilir.

The Role of Diffusion on Reservoir Performance in Underground Hydrogen Storage

Summary Underground hydrogen storage (UHS) has the potential to balance fluctuating sustainable energy generation and energy demand by offering large-scale seasonal energy storage. Depleted natural gas fields or underground gas storage fields are attractive for UHS as they might allow for cost-efficient hydrogen storage. The amount of cushion gas required and the purity of the backproduced hydrogen are important cost factors in UHS. This study focuses on the role of molecular diffusion within the reservoir during UHS. Although previous research has investigated various topics of UHS such as microbial activity, UHS operations, and gas mixing, the effects of diffusion within the reservoir have not been studied in detail. To evaluate the composition of the gas produced during UHS, numerical simulation was used here. The hydrogen recovery factor and methane-to-hydrogen production ratio for cases with and without diffusive mass flux were compared. A sensitivity analysis was carried out to identify important factors for UHS, including permeability contrast, vertical-to-horizontal permeability ratio, reservoir heterogeneity, binary diffusion coefficient, and pressure-dependent diffusion. Additionally, the effect of numerical dispersion on the results was evaluated. The simulations demonstrate that diffusion plays an important role in hydrogen storage in depleted gas reservoirs or underground gas storage fields. Ignoring molecular diffusion can lead to the overestimation of the hydrogen recovery factor by up to 9% during the first production cycle and underestimation of the onset of methane contamination by half of the back production cycle. For UHS operations, both the composition and amount of hydrogen are important to design facilities and determine the economics of UHS, and hence diffusion should be evaluated in UHS simulation studies.

A hydrogeophysical framework to assess infiltration during a simulated ecosystem-scale flooding experiment

This study presents a framework to quantify changes in soil saturation in response to flooding caused by extreme hydrologic perturbation on coastal ecosystems at the interfaces and transition between terrestrial and aquatic systems. Subsurface heterogeneity limits the use of in situ measurements to quantify subsurface flow during flooding due to the spatial discontinuity in the measured data. While geophysical methods, including time-lapse electrical resistivity imaging (ERI), are increasingly used to monitor soil hydrological processes, their abilities to parameterize flow models have been underutilized. This study combines background ERI, ground penetrating radar (GPR), time-lapse ERI, soil characterization, and a numerical flow model developed using an Advanced Terrestrial Simulator (ATS) code to quantify the infiltration pathway and describe the hydrological dynamics during a simulated flooding experiment. We assessed the use of two conceptual models developed using [1] ERI and GPR data that described the stratigraphic distribution, and time-lapse ERI that mapped permeability contrast, and [2] information from a national soil database for capturing changes in saturation. Combining the ERI and GPR results with soil core data revealed the stratigraphic heterogeneity at the site with a silty clay layer from 1 to 2 m between an overlying loamy topsoil and an underlying saturated silty sand. This silty clay layer could restrict deep infiltration. The time-lapse ERI showed up to a 35% decrease in resistivity, which correlated with soil moisture data (R2 value > 0.53) and revealed preferential infiltration zones used to inform the flow model. Numerical simulation results from both the geophysics- and soil database-informed models quantified changes in soil saturation with calculated soil moistures that agreed with field data. The geophysics-informed model captured more of the system’s variability, reflective of shallow subsurface heterogeneities. The framework presented will serve as a precursor for a robust ecohydrological model that can describe the impacts of extreme events induced by climate change on coastal ecosystems.

Assessing mesoscale permeability in unsaturated, fractured, and karstified carbonate reservoirs: a joint geological, petrophysical, and hydraulic approach for the interpretation of injection tests

In the study of subsurface reservoirs, permeability is a key parameter whose evaluation and extrapolation at the desired scale, such as that of the numerical model mesh, are both a necessity and a difficult task. Relating permeability measurements to the geological characteristics of the rock, at intermediate scales seldom characterized, can help understanding the heterogeneity of the medium and correctly determining the permeability at the desired scale. This concern is particularly important in karst reservoirs, which exhibit highly variable permeability at different scales of observation and from one location to another. Here, we study the petrophysical and geological properties of carbonate facies from the centimeter to the meter scale. Several boreholes a few meters apart were cored and exhaustively described. Petrophysical measurements were made on rock samples, while inter-packer injection tests were undertaken to investigate some meter intervals of the medium surrounding the wells. The results show that the investigated medium is a complex multi-medium with a multi-scale heterogeneity. The detailed geological description allowed explaining the differences between the permeability values at different scales and from one interval to another. Relationships were quantified between the texture of the limestone matrix, the density and aperture of the discontinuities, the permeability of the matrix, and the permeability contrast related to the dual medium at the meter scale. A strong correlation between this permeability contrast and the aperture of the discontinuities, itself more correlated to the texture of the rock than to the facies, is highlighted.

Numerical and experimental investigation of dispersed oil-in-water flow in porous media

Reservoir heterogeneity continues to be a major challenge in the oil industry's efforts to minimize the water cut, improve the volumetric sweep efficiency, and, ultimately, increase oil recovery. Injection of oil-in-water (O/W) dispersions can regulate the permeability contrast between these layers. Dispersed oil droplets can propagate into the reservoir and partially plug porous spaces in high-mobility zones. This study is devoted to highlighting a number of areas where there is a lack of knowledge concerning O/W dispersion injection in porous media in order to evaluate the entrapment mechanisms, pressure drop, and permeability reduction. A series of O/W dispersion injection experiments were conducted on various cylindrical sandstone core plugs. The effluent shows a significant decline in oil droplet size. A mathematical model based on the experimental setup was developed to describe the dynamics of the dispersion flow. The finite element method (FEM) was employed to numerically solve the governing equations. The numerical model involves the discretization of convection-diffusion, modified Darcy, and pressure equations. Verification of the numerical model was performed by comparing the pressure drop and permeability decline to the results of analytical solutions. The model was validated relatively well against experimental data. Finally, the current study provides a fundamental insight into a number of factors that may influence O/W dispersions flow in porous media. However, further research and improvements to the model complexity are required for field applications.