Low-permeability Formations Research Articles

Multivariate Statistical Approach and Assessment of Pollution of Water and Sediments in Karstic Springs of Transboundary Aquifer Žumberak–Samoborsko Gorje Mountain (Croatia/Slovenia)

This study highlights the geochemistry of water and sediments of the karstic springs of the transboundary aquifer (TBA) Žumberak–Samoborsko Gorje Mt. (NW Croatia). After calculating pollution indices, the analysis showed that the sediments are unpolluted. The geo-accumulation index (Igeo) showed only the elements Ba and Rb, indicating moderate levels of pollution, with the highest values in springs Vapnik and Bistrac. Statistical analysis confirmed their natural origin. The water of these springs is under possible anthropogenic influence as indicated by elevated concentrations of total nitrogen (TN) and total phosphorus (TP). According to a principal component analysis (PCA) for elements in sediments, PC1 described a combined lithogenic and oxidative–reductive influence, PC2 described a combined geological background including total organic carbon (TOC) content and oxidative–reductive influence, while TOC had the greatest influence on PC3. Depending on element composition, the factor scores related to PC1 and PC2 resulted in two different groups of sites, while the factor scores concerning PC1 and PC3 did not show separation in two groups. The hierarchical cluster analysis showed three clusters in relation to the content of the elements. The correlation coefficient between the sediment and related water samples showed that the springs placed in a low-permeability formation (dolomite) had a strong positive coefficient of correlation.

DIGITAL SOLUTION FOR OPTIMIZATION OF FORMATION TESTING DESIGN

Evaluation of pumping time to receive a clean sample during fluid sampling job with wireline formation tester as well as evaluation of pumping scenarios to minimize sampling duration under existing constrains (reservoir and sandface constrains, safety etc.) are actual problems especially for fluid sampling in low-permeability formation. The article describes the digital solution allowing to simulate mud filtrate invasion in near-wellbore zone during well drilling and mud filtrate displacement by reservoir fluid during fluid sampling job with taking into account a formation damage dynamics. In this way, the software is able to evaluate depth of mud filtrate invasion and simulate both the multiphase inflow dynamics and the skin-factor dynamics during sampling job and predict sampling duration. To take into account a complex, essentially non-1D geometry of multiphase fluid flow in near-wellbore zone during fluid sampling, the special upscaling technique was developed. This upscaling technique is based on modification of 1D model by introduction of «effective» mud filtrate invasion profile and «geometry factor» which depend on ratio of vertical to horizontal permeabilities. The correlations between empirical model parameters and ratio of vertical to horizontal permeabilities were obtained by matching results of «pseudo 2D» simulations of pumping dynamics with results of 2D / 3D simulations conducted using commercial simulators ECLIPSE® and COMSOL Multiphysics®. The developed «pseudo 2D» model is computationally fast ones that allows to effectively conduct sensitivity study as well as adjust the model parameters and sampling scenario in real time in accordance with the real-time wireline formation tester measurements.

Permeability Upscaling Conversion Based on Reservoir Classification

Deep and ultra-deep reservoirs are characterized by low porosity and permeability, pronounced heterogeneity, and complex pore structures, complicating permeability evaluations. Permeability, directly influencing the fluid production capacity of reservoirs, is a key parameter in comprehensive reservoir assessments. In the X Depression, low-porosity and low-permeability formations present highly discrete and variable core data points for porosity and permeability, rendering single-variable regression models ineffective. Consequently, accurately representing permeability in heterogeneous reservoirs proves challenging. In the following study, lithological and physical property data are integrated with mercury injection data to analyze pore structure types. The formation flow zone index (FZI) is utilized to differentiate reservoir types, and permeability is calculated based on core porosity–permeability relationships from logging data for each flow unit. Subsequently, the average permeability for each flow unit is computed according to reservoir classification, followed by a weighted average according to effective thickness. This approach transforms logging permeability into drill stem test permeability. Unlike traditional point-by-point averaging methods, this approach incorporates reservoir thickness and heterogeneity, making it more suitable for complex reservoir environments and resulting in more reasonable conversion outcomes.

Experimental investigation of capillary pressure diagram in oil/water transition zone of low-permeability reservoirs

The oil/water transition zone, particularly pronounced in low-permeability formations with small pore diameters and high capillary pressure, contains a substantial portion of original oil in place. The capillary pressure curves provide essential data for the calculation of the original oil in place as well as the oilfield development simulation. However, the traditional single capillary pressure curve cannot provide enough information. To address this challenge, an experimental investigation was conducted to explore the capillary pressure diagrams within the oil/water transition zone of low-permeability reservoirs. The results shed light on the complex behavior of capillary pressure, the influence of initial water saturation, and the relationship between initial oil saturation and residual oil saturation. Incorporating the behavior of capillary pressure into reservoir simulation models can enhance reservoir characterization and improve the accuracy of oil production performance in low-permeability reservoirs.

What You Don’t Know About Chevron’s New 20K Anchor Project

_ After overcoming the impacts of the COVID-19 pandemic and closing significant technology and regulatory gaps, Chevron’s $5.7 billion Anchor project in the US Gulf of Mexico (GOM) is nearly ready to start producing oil. When it finally does, it will mark the start of the “20K” era for the deepwater oil and gas industry. The term 20K refers to the project’s core technologies, designed to handle wellhead pressures of up to 20,000 psi—a first for the subsea market. The advancement opens the door to previously inaccessible reservoirs by stretching the boundary of deepwater technology beyond the technical limit of 15,000 psi established in the past decade. In particular, the drive to reach such extremes is a response to the demands posed by the Lower Tertiary Wilcox play which Chevron pioneered the development of in 2014 with its Jack/St. Malo project. Output from the high-pressure, low-permeability, and ultradeep formation is expected to rise from last year’s 270,000 B/D to around 750,000 B/D by 2028. This would represent a shift from 13% to nearly 40% of the US GOM’s total of roughly 2 million B/D, according to Enverus Intelligence Research. The success of just a handful of projects like Anchor is crucial for achieving these projections. Located approximately 140 miles offshore Louisiana in about 5,000 ft of water, Chevron holds a 62.8% share in the project, with TotalEnergies owning the remaining interest. The initial phase includes seven wells targeting reservoir depths between 30,000 and 34,000 ft. Chevron has drilled three so far. Anchor’s semisubmersible floating production unit (FPU) arrived in the GOM last year after its hull was built in South Korea and topsides integrated along the Texas coast. The FPU has nameplate capacity of 75,000 B/D but upon delivery, Chevron determined it could make small modifications to boost the facility’s peak throughput to 86,000 B/D—an almost 15% increase. At this year’s Offshore Technology Conference (OTC) in Houston, Chevron’s Anchor project team offered a behind-the-scenes look at their journey to the precipice of first oil. Drawing from several papers they presented, here are some of Anchor’s biggest challenges and achievements. A Project of Firsts The nature of the Anchor project is such that it involves a number of industry firsts and records. At the top of that list is Transocean’s Deepwater Titan drillship which Chevron inked a 5-year $830 million contract for while it was still under construction in 2018. The rig began operations in the GOM in June 2023 as the second eighth-generation drillship ever built but holds claim to being the first ever rated for 20K operations. Originally planned to be a 15K-rated vessel, the Deepwater Titan was upgraded on Chevron’s request to host two NOV-supplied 20,000-psi blowout preventers (BOPs). Combined with the lower marine riser package, the BOP stack weighs in at more than 1.1 million lbs. Chevron points out in OTC 35148 that the BOPs were not needed to drill the wells—for that, 15,000-psi BOPs would have sufficed—but they were required for well control during the completion phase when hydrocarbons are most likely to flow to surface.

Fluid-driven aseismic fault slip with permeability enhancement and dilatancy

Injection-induced seismicity and aseismic slip often involve the reactivation of long-dormant faults, which may have extremely low permeability prior to slip. In contrast, most previous models of fluid-driven aseismic slip have assumed linear pressure diffusion in a fault zone of constant permeability and porosity. Slip occurs within a frictional shear crack whose edge can either lag or lead pressure diffusion, depending on the dimensionless stress-injection parameter that quantifies the prestress and injection conditions. Here, we extend this foundational work by accounting for permeability enhancement and dilatancy, assumed to occur instantaneously upon the onset of slip. The fault zone ahead of the crack is assumed to be impermeable, so fluid flow and pressure diffusion are confined to the interior, slipped part of the crack. The confinement of flow increases the pressurization rate and reduction of fault strength, facilitating crack growth even for severely understressed faults. Suctions from dilatancy slow crack growth, preventing propagation beyond the hydraulic diffusion length. Our new two-dimensional and three-dimensional solutions can facilitate the interpretation of induced seismicity data sets. They are especially relevant for faults in initially low permeability formations, such as shale layers serving as caprock seals for geologic carbon storage, or for hydraulic stimulation of geothermal reservoirs. This article is part of the theme issue ‘Induced seismicity in coupled subsurface systems’.

A new formulation for removing condensate blockage for low permeable gas reservoir

Condensate blockage significantly impairs gas production in low-permeability reservoirs by reducing gas relative permeability and increasing condensate saturation near the wellbore. Particularly acute in reservoirs with low pressure and permeability, effective solutions are required to mitigate this formation damage. This study introduces a novel acid treatment strategy aimed at enhancing the injectivity index in gas reservoirs afflicted by condensate blockage. Leveraging mineralogical analysis, Hydrochloric Acid (HCl) was identified as the optimal acidizing agent. The most effective concentrations of HCl for rock dissolution—15% and 7.5%—were determined through dissolution tests. The research further advances by adding methanol to the acid mix, resulting in three distinct formulations: HCl 15 wt%, HCl 15 wt% + methanol, and HCl 7.5 wt% + methanol. Comprehensive wettability alteration tests and coreflood experiments were conducted to evaluate the efficacy of these systems in permeability enhancement. The HCl 7.5 wt% + methanol formulation demonstrated superior performance in permeability improvement and condensate blockage reduction, outshining the other systems. Notably, this new acid system effectively altered wettability from hydrophobic to hydrophilic, facilitating the passage of condensate through the pore throats and thus aiding in the removal of blockages. The integration of methanol with HCl, particularly at a 7.5 wt% concentration, represents a significant advancement in the treatment of condensate blockage in gas reservoirs, promising to improve gas recovery rates by addressing the challenges posed by low-permeability formations.

Influence of sedimentary structure and pore-size distribution on upscaling permeability and flow enhancement due to liquid boundary slip: A pore-scale computational study

Low-permeability sedimentary formations, such as tight sandstones, exhibit fluid flow and transport phenomena distinct from those in conventional porous systems due to the dominance of micro- to nanometer-sized pores and variable amounts of boundary slip. The widely used traditional no-slip boundary condition often fails to accurately describe fluid behavior in these formations. A knowledge gap exists in understanding how liquid slip influences fluid dynamics in complex, heterogeneous sedimentary structures, as previous studies have primarily focused on simplified, homogeneous pore geometries. In this study, we investigated the impact of boundary slip on low-Reynolds number fluid dynamics within synthetically designed two-dimensional graded and random pore networks with varying pore-size distributions to account for heterogeneity. Our results showed that velocity variance increased with increasing heterogeneity, following a power-law relationship. The power-law exponents decreased with boundary slip, quantifying how boundary slip mitigated the impact of heterogeneity on velocity variance. We developed a theoretical model to predict asymptotic flow enhancement and derived constitutive relations to estimate the coefficient C and maximum flow enhancement (ΔE) based on the pore-to-grain size ratio and porosity. Energy dissipation increased with both heterogeneity and boundary slip, which we identified as the primary mechanism contributing to asymptotic flow enhancement. This relationship was illustrated by a 1:1 linear correlation between maximum energy dissipation and maximum flow enhancement, regardless of heterogeneity, indicating that energy dissipation due to boundary slip entirely controls the emerging fluid dynamics. The presented theoretical model and constitutive equations offer practical applications for optimizing fluid dynamics in heterogeneous formations.

Characteristics and Mechanisms of CO2 Flooding with Varying Degrees of Miscibility in Reservoirs Composed of Low-Permeability Conglomerate Formations

The reservoir type of the MH oil field in the Junggar Basin is a typical low-permeability conglomerate reservoir. The MH oilfield was developed by water injection in the early stage. Nowadays, the reservoir damage is serious, and water injection is difficult. There is an urgent need to carry out conversion injection flooding research to improve oil recovery. The use of CO2 oil-flooding technology can effectively supplement formation energy, reduce greenhouse gas emissions, and improve economic benefits. In order to clarify the feasibility of CO2 flooding to improve oil recovery in conglomerate reservoirs with low permeability, strong water sensitivity, and severe heterogeneity, this paper researched the impact of CO2 miscibility on production characteristics and mechanisms through multi-scale experiments. The aim was to determine the feasibility of using CO2 flooding to enhance oil recovery. This study initially elucidated the oil displacement characteristics of varying degrees of miscibility in different dimensions using slim tube experiments and long core experiments. Subsequently, mechanistic research was conducted, focusing on the produced oil components, changes in interfacial tension, and conditions for pore mobilization. The results indicate that the minimum miscibility pressure (MMP) of the block is 24 MPa. Under the slim tube scale, the increase in the degree of miscibility can effectively delay the gas breakthrough time; under the core scale, once the pressure reaches the near mixing phase, the drive state can transition from a non-mixed “closed-seal” to a “mixed-phase” state. Compared to the immiscible phase, the near-miscible and completely miscible phase can improve the final recovery efficiency by 9.27% and 18.72%. The component differences in the displacement products are mainly concentrated in the high-yield stage and gas breakthrough stage. During the high-yield stage, an increase in miscibility leads to a higher proportion of heavy components in the produced material. Conversely, in the gas breakthrough stage, extraction increases as the level of mixing increases, demonstrating the distinct extracting characteristics of different degrees of mixed phases. The core experiences significant variations in oil saturation mostly during the pre-gas stage. CO2 miscible flooding can effectively utilize crude oil in tiny and medium-sized pores during the middle stage of flooding, hence reducing the minimum threshold for pore utilization to 0.3 μm.

Modeling gas flow in low-permeability formations: An efficient combination of mixed finite elements and high order time integration schemes

Numerical simulation of gas flow in low permeability formations is a challenging task due to the high nonlinearity induced by (i) the compressibility of the gas, (ii) the Klinkenberg slippage effect and (iii) the Langmuir adsorption of the gas on the pore surface. Because of these nonlinearities, modeling gas flow in low permeability formations requires a great deal of computational effort. In this work, we develop an efficient numerical model using advanced spatial and temporal discretization methods for a simultaneous solution of the coupled equations of gas flow, cubic Peng-Robinson equation of state, slippage effect and Langmuir adsorption. The spatial discretization is performed with the lumped hybrid formulation of the mixed finite element method which is well adapted for fluid flow in heterogeneous porous media. The time integration is performed with high-order methods via the method of lines (MOL) which allows large time steps and efficient solution of the nonlinear system of equations. Numerical experiments, performed for gas extraction in a heterogeneous domain, point out the high efficiency of the new model since it can be until 10 times more efficient than the classical first-order time discretization method. Results of global sensitivity analysis show that the intrinsic gas-phase permeability and the Klinkenberg factor are the most influential parameters controlling the pumping rate in the case of gas extraction in a homogeneous domain.

Effect of fracture distribution on extraction efficiency in low-permeability NAPL-contaminated formations

Hydraulic fracturing offers an effective solution to the challenge of remediating low-permeability contaminated formations by improving substance transport rates. In this study, COMSOL Multiphysics, a large-scale multi-physics coupled simulation software, was employed to simulate enhanced extraction and remediation of low permeability non-aqueous phase liquid (NAPL)-contaminated formations using hydraulic fractures. The results obtained indicate that fracturing and enhanced extraction can effectively improve the NAPL removal rate. The NAPL removal rate increased with increasing depth of the extraction well screens, fracture length, and fracture spacing. Through a coupling analysis of multiple factors and working conditions, the extraction well screens are suggested to be buried within the lower one-third of the low-permeability contaminated formation, and the length of a single fracture should be within 50%–80% of the extraction radius. When the distance between the two fractures was greater than 1.75 m, the enhancement effect of the fracture length was further promoted. Consequently, a reasonable configuration of fracture length, quantity, and spacing can effectively broaden the influence radius of extraction wells.

Understanding Plugging Agent Emplacement Depth with Polymer Shear Thinning: Insights from Experiments and Numerical Modeling

Polymer-plugging agents are widely employed in profile control and water-plugging measures, serving as a crucial component for efficient reservoir development. However, quantitatively monitoring the emplacement depth of polymer-plugging agents in low-permeability and high-permeability layers remains a challenging bottleneck. Presently, insufficient attention on shear thinning, a critical rheological property for water shut-off and profile control, has limited our understanding of polymer distribution laws. In this study, polymer shear-thinning experiments are firstly conducted to explore polymer variations with flow rate. The novelty of the research is that varying polymer viscosity is implemented instead of the fixed-fluid viscosity that is conventionally used. The fitted correlation is then integrated into the 2D and 3D heterogeneous numerical models for simulations, and a multivariate nonlinear regression analysis is performed based on the simulation results. The results show that lower polymer emplacement depth ratios corresponded to higher viscosity loss rates under the same flow rate. An increase in the initial permeability ratio corresponds to a decrease in the emplacement ratio, along with a reduction in the fraction of the plugging agent penetrating the low permeability formations. The model was applied to the Kunan Oilfield and demonstrated a polymer reduction of approximately 3000 tons compared to traditional methods. Despite the slightly complex nature of the multivariate nonlinear mathematical model, it presents clear advantages in controlling plugging agent distribution and estimating dosage, laying good theoretical ground for the effective and efficient recovery of subsurface resources.

MAINTAINING GAS RECOVERY IN LOW-PERMEABILITY FORMATIONS

The purpose of this work was to ensure efficient gas production in low-permeability and heterogeneous formations by numerically modeling the distribution of reservoir pressure drop around production and injection wells. To investigate this goal, we used a simulation based on the combined finite-element-difference method for nonstationary Leibenson piezoelectric conductivity problems. The method is based on the combination of elements of the already known finite difference and finite element methods for the nonstationary piezoelectric conductivity problem. The study found that there are many factors that affect the process of maintaining gas production in poorly permeable areas of a gas-bearing formation. Among them, first of all, after increasing the permeability of the corresponding section of the reservoir where production is created. Another important factor for maintaining gas recovery is the ability to naturally or artificially maintain gas phase infiltration within the affected reservoir area. This aspect is especially important for ensuring stable gas recovery over a long period of operation. During the intensive and long-term operation of the working area of the gas-bearing formation, additional injection wells were installed in the complex of production wells to avoid its depletion. It is important to note that provided a high level of gas phase penetration at the beginning of field operation, other factors of the production process, such as additional production wells and infiltration within the working area, have a lesser impact on the overall pressure distribution in this area. Thus, the study shows that with the passage of time and prolonged operation of the working section of the reservoir, the influence of its penetration decreases, but the importance of injected substances in the injection wells and gas phase infiltration within this section of the reservoir increases.

Flowback Rates for Pump-In/Flowback Test

Summary The pump-in/flowback test (PIFT), often referred to as the diagnostic fracture injection test (DFIT) with flowback, offers notable advantages in terms of time efficiency and accuracy, particularly in the context of low-permeability formations. The key to the success of this test lies in the careful selection of an optimal flowback rate to yield meaningful results. The fundamental assumption underlying the pressure analysis of these tests is the uniform closure of fractures during the flowback phase, which is considered the default fracture closure mode in current analyses. In this study, we present evidence that challenges the validity of this assumption, highlighting instances where unsuitable flowback rates can lead to nonuniform fracture closure and result in abnormal pressure data. To address this challenge, we identify different closure modes through the signature of fracture closure in the excessive bottomhole pressure decline curve. Subsequently, we propose an optimal range of flowback rates using a scaling analysis approach to obtain a uniform closure mode in an extended openhole section of a vertical well. Our method has been rigorously validated through 3D numerical simulations and field studies, enhancing its reliability and applicability. This approach helps operators to conduct effective tests in complex situations, overcoming a barrier to widespread test application.

Investigating the influence of Joule-Thomson cooling on hydrate reformation near the wellbore

Hydrate reformation, caused by the Joule-Thomson effect (JTE) during depressurization, poses a major obstacle to efficient gas production. This study examines the impact of the JTE on hydrate reformation near the wellbore during depressurization, focusing on the influences of gas-to-water ratio, depressurization range, and permeability. The results indicate that JTE significantly contributes to a gradual temperature decrease, leading to hydrate reformation. Reformed hydrates, potentially saturating up to 80%, initially appear near the wellbore then move away due to intense depressurization that eroded their inner surface, creating a moving low-permeability barrier that obstructs fluid flow and reduces gas-water production rates. Formations with higher permeability and gas saturation experience intensified JTE, leading to faster temperature drops, shorter hydrate reformation times, and quicker expansion of secondary hydrate bands. The study also evaluates the effectiveness of wellbore heating to mitigate hydrate reformation. Wellbore heating is found to be more effective in low-permeability formations, but only within a 0.5 m radius near the wellbore in high-permeability formations. This research suggests narrower depressurization ranges to prevent hydrate reformation and indicates the limited impact of wellbore heating on enhancing gas production. The findings have significant implications for preventing hydrate reformation near the wellbore and improving hydrate production efficiency.

About flooding of low-permeable formations

Due to the depletion of hydrocarbon reserves in traditional reservoirs with good filtration and reservoir properties, there is currently increasing interest in hard-to-recover reserves, and the main difficulty in developing such reservoirs is the efficiency of reservoir pressure maintenance systems. When developing low-permeability reservoirs, various mechanisms of oil displacement during flooding can be distinguished. For reservoirs with permeability less than 1 mD, there is no need to maintain high wellhead pressure; moreover, with a large accumulated compensation, stopping the maintenance of reservoir pressure for up to six months does not lead to a drop in production, which creates the prerequisites for organizing cyclic flooding. This will solve a number of problems that arise while maintaining reservoir pressure when working in such conditions.
 The facies structure of reservoirs sometimes has a decisive influence on the performance of wells and their interinfluence. The transition to the development of fields with a complex geological structure, low filtration characteristics of the formation, the existence of geological bodies with different properties requires not only careful formation of a conceptual understanding of the field, but also the creation of detailed facies digital maps taking into account the existence of zones with different sedimentation, which, as a consequence, creates zones with different filtration and capacitance properties, requiring different approaches to development.

Well pattern infilling as a way to increase low-permeability reservoirs development efficiency

The subject of the study is to study the influence of the well grid density for a low-permeable heterogeneous terrigenous formation in order to determine the optimal strategy for the reserves development. The paper analyzes various development systems implemented at the facility, as well as changes that occurred as a result of infill well drilling. In the process of information processing, actual data on the operation of wells at various sites were used, the values of recoverable reserves were estimated using statistical methods, calculations of various options were carried out using a hydrodynamic model in order to determine the implemented systems effectiveness, as well as to find ways to optimize them. It was found that for the conditions considered, the well grid infilling made it possible to increase the recoverable reserves amount by increasing the reservoir development coverage. Within the framework of the considered geological facility, the functional dependence of the oil recovery ratio and the the well grid density is obtained. The proxy modeling has shown that the necessary condition for maintaining the selections intensity is to maintain the flooding system rigidity. Taking into account the results obtained, the paper describes an approach based on which the potential for additional local grid infilling was estimated, taking into account the geological potential for involving reserves in development and the technological risk associated with zones of abnormally high reservoir pressure. Keywords: field development, low-permeability reservoirs, hard-to-recover reserves, infilling, drilling.

Assessment of Morphometric and Hypsometric Analysis of the Ruste Basin Using Remote Sensing and Geographical Information System Techniques

A basin’s characteristics and features need to be comprehended completely by conducting morphometric analysis, such as evaluating the basin’s size, form, and surface features, to estimate floods and erosion rates properly. The main objective of this investigation is to evaluate morphometric measures and hypsometric analysis of Erbil’s Ruste Basin employing remote sensing and geographical information system methods. To investigate the significant tributaries of the selected area, the hydrology tool within the Spatial Analysis Tools of ArcGIS, version 10.7, was utilized to define the basin boundaries, map the drainage networks, and obtain topographic data. The findings of the linear morphometric parameters revealed that the logarithmic relationship between stream orders and stream numbers was negative. The difference in stream order and number seen in the watershed is due to topography and bedrock influence. The results also showed a negative correlation between stream length and stream order, and a coefficient of determination of 0.972, which indicates that the basin is made of low-permeability formation and subsoil materials. Considering the areal morphometric parameters, the circularity ratio, elongation ratio, and form factor are 0.594, 0.853 and 0.572, respectively, suggested a semi-circular shape. A drainage density value of 2.259 km-1 showed that the Ruste Basin is a basin with steeply to very steeply sloping hilly terrain with varying plant covering. Furthermore, the Ruste Basin has high relief and slope with a relief ratio of 0.151 and basin relief of 2.576 km, both of which imply that it has a steep slope with high erosive force, limited infiltration, and a high runoff rate. Ruste Basin’s ruggedness number was 5.819, indicating that it has badlands topography. The average hypsometric integral was 0.467, denoting a mature basin featuring S-shaped hypsometric curves. In conclusion, the results showed that analysis of morphometric parameters and hypsometric integral and curve provides us with a notion to basin characterization and guidance to making appropriate decisions to establish effective actions to sustainable water and soil conservation and natural resources management through applying water harvesting methods, check dams, and bench terraces.

Single fluid-driven crack propagation in analogue rock assisted by chemical environment

During the operation of hydraulic fracturing as used in many geo-energy and geo-environment applications, chemical stimulation is often incorporated for cracking enhancement in low-permeability geological formations for the purpose of an optimization of energy recovery. The mechanism of subcritical crack propagation in a chemically reactive environment is essential for understanding of the involved coupled chemo-mechanical process and a better control of acid-assisted hydraulic fracturing. It has been postulated that the rate of crack propagation under environmental loads is inherited from the chemical processes involved including the reaction and the diffusive transport. However, laboratory explorations focusing on the evolving interplay between the propagation of a fluid-pressurizing individual crack and the environment it is subject to via a variable chemical intensity imposed have been rare. Here we present an experimental investigation on a single tensile crack propagation in alginate hydrogel as an analogue material for brittle rocks, driven by the injection of a chemically reactive fluid kept at constant pressure using a Hele-Shaw cell setup. We show that an intensified chemical environment can accelerate tensile crack propagation in both subcritical crack growth and fracturing regimes, while leading to the Region III fracturing of less brittle characteristics. During the experiment, crack-tip blunting upon injection of reactive solutions was observed, suggesting a competing mechanism between the crack-tip geometry induced toughening and the chemically induced softening within the process zone as the crack advances. Our results provide quantitative insights into how a chemically reactive environment facilitates the growth of a single macroscopic crack of mode I opening in a low-permeability matrix through coupled chemo-mechanical feedback. The imposed chemical environment promotes crack propagation while alleviating the stress concentration at the advancing crack tip, suggesting a more energy-efficient method compared to pure water fracturing. We anticipate our experimental investigation presented here to be a starting point of sound laboratory support for future studies towards a more controllable technique of chemical stimulation in geomaterials as well as complementing the ongoing modeling efforts in reactive chemo-mechanics.

NUMERICAL SIMULATION METHOD IN LOW PERMEABLE ANISOTROPIC RESERVOIRS IN ORDER TO INCREASE OIL RECOVERY


 
 The object of study is the filtration process in weakly permeable anisotropic formations (SAP). The work is devoted to the evaluation of the process of oil-bearing formation depletion, using as a criterion the distribution of reservoir pressure near the system of production and injection wells, taking into account the anisotropy of the permeability of the oil phase. In the course of the study, a combined numerical modeling method based on the finite element and finite difference methods is presented, which allows determining the value of reservoir pressure at any point in the computational domain. The finite-element-difference method proposed in this paper, which combines the advantages of the finite-element method and the finite-difference method to solve the nonstationary piezoelectric conductivity problem, taking into account the heterogeneous distribution of various filtration parameters within the deformed formation and at its boundaries, allows us to adequately calculate the distribution of reservoir pressure in real-world well operation conditions, which gives a number of advantages over existing methods. It was found that the effect of oil phase permeability in the shear direction dominates the effect of permeability in the axial directions. This is due to the fact that, according to the information obtained, for the effective use of anisotropic low-permeability formations, it is necessary to place production and injection wells in areas with relatively low anisotropy of formation permeability, especially to avoid areas with the presence of shear permeability of the formation. It is important to locate wells so that, on the one hand, there is no blockage of oil from the low permeability side, and, on the other hand, there is no rapid depletion of the formation from the high permeability side and the mutual exchange between the production and injection wells does not stop. When placing a system of production and injection wells in anisotropic formations of an oil field, it is necessary to conduct a systematic analysis of the surrounding anisotropy of the formations in order to place them in such a way that would ensure effective dynamics of filtration processes around these wells and increase oil recovery.