Reservoir Flow Research Articles

Research on the Blocking Mechanism of Stagnant Water and the Prediction of Scaling Trend in Fractured Reservoirs in Keshen Gas Field

In this paper, well Keshen 221 was taken as the research object. The stagnant water–rock static experiment showed that, after 8 weeks of the residual water–rock static reaction, the pore size of the inner profile of the rock slice increased from 5 μm to 90 μm, and calcium carbonate crystals were deposited in the hole. Combined with the microscopic visualization model, it is observed that the reservoir blockage mostly occurs at the pore throat diameter, and the small fracture (30 μm) is blocked first, then the large fracture (50 μm). So, it is inferred that the blockage of the reservoir flow channel is caused by the migration of the crystals precipitated by the interaction between the stagnant water and the reservoir rock. On this basis, the TOUGHREACT reservoir model was further constructed to simulate the scaling of the stagnant water in the reservoir matrix and used to compare the scaling of the fractures with 7% and 30% porosity and the retained water at 0.658 m and 768 m. The pre-results of reservoir scaling show that the scaling is more serious when the fractures occur in the far well zone than when the fractures occur in the well entry zone. At the same location, the deposition of large fractures is six times that of small fractures, and the scaling is more severe in large fractures.

Quantitative Analysis of Fracture Network Geometry on Fluid Flow and Heat Transfer in Hot Dry Rock Geothermal Reservoirs

Quantitative Analysis of Fracture Network Geometry on Fluid Flow and Heat Transfer in Hot Dry Rock Geothermal Reservoirs

Numerical investigation into the acid flow and reaction behavior in the tight, naturally fractured carbonate reservoir during acid fracturing

Tight naturally fractured carbonate reservoirs require acid fracturing to build the connectivity between the wellbore and natural fractures (NFs), where hydrocarbon is stored. The high leakoff nature of the NF complicates the acid flow and etching pattern, raising the difficulty in acid fracturing design and optimization. To explore the acid flow and reaction behavior in such reservoirs, an acid fracturing model accounting for the NF distribution is developed, which consists of a fracture surface characterization model, a fracture propagation model, and an acid-etching model. Based on the model, the effects of injection parameters and the NF properties on the effectiveness of acid fracturing are investigated. Then, strategies for acid fracturing the tight naturally fractured carbonate reservoirs are proposed. Results show that high pumping rates and retarded acids with low hydrogen ion (H+) diffusion coefficient is conducive to achieving a long acid penetration distance, while a low pumping rate and acids with a high H+ diffusion coefficient facilitates the NF etching. Therefore, a large stimulated area can be achieved by applying a multi-stage alternating injection of the crosslinked acid with a high pumping rate followed by the gelled acid with a low injection rate. NFs impact acid fracturing in two distinct ways: enhancing the non-uniform etching of the fracture surface and reducing the effective acid-etched fracture length through high leakoff. When NF density is high, leakoff control techniques should be employed; and when the NF inclination is high, non-uniform etching techniques should be used to generate acid-etched channels in flow barriers.

A hybrid multiscale model for fluid flow in fractured rocks using homogenization method with discrete fracture networks

Fluid flow in subsurface tight reservoirs containing pores, microcracks and macrocracks is notably influenced by the characteristics of macro/micro-cracks. A novel hybrid multiscale model is proposed to address the response of macrocracks and pores/microcracks in different spatial scales. Specifically, an equivalent macroscopic model (EMM) deduced from locally periodic representative element volume (REV) is developed using the asymptotic homogenization method to represent the poroelastic behavior of porous medium with microcracks. Simultaneously, the macrocracks are modeled explicitly using the discrete fracture model (DFM), where the hydraulic properties of cracks influenced by fluid pressure gradient is represented by the nonlinear opening/closure behavior. The obtained hybrid model takes into account the heterogeneous nature of fractured rock masses containing pores, micro/macro-cracks, which is fundamental to describe fluid flow behavior in fracture-matrix system. Specialized finite elements, regular meshing technique and adaptive time stepping algorithm are adopted to improve the computational efficiency. The hybrid multiscale model is firstly validated step by step to demonstrate the accuracy and then used to simulate fluid flow in fractured rock reservoir, shedding light on the underlying mechanisms of the enhanced flow capacity resulting from microcrack distribution, connectivity, and macrocrack stimulation.

Impact of dual-fracture location on heat extraction from Enhanced geothermal system in low-permeability reservoirs

As environmental and economic issues exacerbated by traditional fossil fuels intensify, Dry Hot Rock geothermal energy has garnered significant attention due to its immense potential. Current research predominantly focuses on the heat extraction effectiveness in complex fractures within Enhanced Geothermal Systems, with relatively less emphasis on fluid behavior between large fractures. This study employs finite element software to establish a multi-horizontal well model in a low permeability reservoir (5 × 10-17 m2), analyzing the impact of different spatial configurations of two fractures on fluid flow, heat transfer, and heat extraction efficiency. The results indicate that fractures are the primary channels for fluid flow in low permeability reservoirs. Optimal heat extraction occurs when fractures are parallel, spaced 100 m apart, and perpendicular to the horizontal well, with significant threshold effects of fracture spacing and angle on temperature distribution. The highest heat extraction is achieved at a 37° intersection angle of fractures at the production well. Over a 60-year production period, reservoir extraction degrees for parallel or intersecting fractures range from 8 % to 15 %, while that for fracture communication between injection and production well horizontal segments is only 1.91 % to 3.01 %. Under the optimal injection scenario, cumulative 60-year heat production for parallel, intersecting, and communicating fractures is 2.13 × 1018J, 2.20 × 1018J, and 2.22 × 1018J, respectively, with the best heat extraction efficiency when fractures communicate. Additionally, under constant flow rate and inlet temperature, outlet temperature and system thermal power show near-linear declines, while reservoir extraction degree rises linearly. This study provides crucial theoretical support and practical guidance for the efficient extraction of geothermal energy.

Development of Machine Learning-Based Production Forecasting for Offshore Gas Fields Using a Dynamic Material Balance Equation

Offshore oil and gas fields pose significant challenges due to their lower accessibility compared to onshore fields. To enhance operational efficiency in these deep-sea environments, it is essential to design optimal fluid production conditions that ensure equipment durability and flow safety. This study aims to develop a smart operational solution that integrates data from three offshore gas fields with a dynamic material balance equation (DMBE) method. By combining the material balance equation and inflow performance relation (IPR), we establish a reservoir flow analysis model linked to an AI-trained production pipe and subsea pipeline flow analysis model. We simulate time-dependent changes in reservoir production capacity using DMBE and IPR. Additionally, we utilize SLB’s PIPESIM software to create a vertical flow performance (VFP) table under various conditions. Machine learning techniques train this VFP table to analyze pipeline flow characteristics and parameter correlations, ultimately developing a model to predict bottomhole pressure (BHP) for specific production conditions. Our research employs three methods to select the deep learning model, ultimately opting for a multilayer perceptron (MLP) combined with regression. The trained model’s predictions show an average error rate of within 1.5% when compared with existing commercial simulators, demonstrating high accuracy. This research is expected to enable efficient production management and risk forecasting for each well, thus increasing revenue, minimizing operational costs, and contributing to stable plant operations and predictive maintenance of equipment.

A coupled displacement-pressure model for elastic waves induce fluid flow in mature sandstone reservoirs

Elastic (seismic) wave stimulation is considered one of the unconventional enhanced oil recovery (EOR) methods. Increasing water quantity in the high permeability layer of a mature oil reservoir is highly challenging and can significantly decrease the ultimate recovery due to the reservoir heterogeneity. Using seismic waves can be considered low-cost, environmentally friendly, and illuminates the entire reservoir size compared to conventional EOR methods. A numerical model is developed by extending the Quintal approach for seismic attenuation due to wave-induced fluid flow (WIFF) to incorporate capillary pressure in partially saturated porous media and shift undrained boundary conditions to exclude external flow stress for drained boundary conditions. Therefore, the fluid distribution due to the capillary effect makes the developed finite element method (FEM) u-p model more widely applicable for oil recovery in mature reservoirs. A two-layer partially saturated media was subjected to compressive seismic stress at low frequency (3 Hz). The results indicated that the vertical displacement gradients of the bottom and upper layers decline with excitation time for both fully and partially saturated media. On the other hand, partially saturated pore pressure gradients of both the upper and bottom layers have higher amplitudes with excitation time than fully saturated pore pressure gradients due to the influence of capillar pressure. The cumulative crossflow oil volume for 180 days of continuous stimulation was 1176 bbl, 1032 bbl, and 648 bbl in low permeability layers: 200 md, 100 md, and 50 md, respectively. Therefore, the developed model has the potential for field-scale EOR applications. The study also suggests coupling elastic EOR with CO2 flooding to recover more oil due to increasing fluid mobility and relative permeability to oil in low-permeability reservoirs or tight formations.

Improved Fracture Permeability Evaluation Model for Granite Reservoirs in Marine Environments: A Case Study from the South China Sea

Permeability is a crucial parameter in the exploration and development of oil and gas reservoirs, particularly in unconventional ones, where fractures significantly influence storage capacity and fluid flow. This study investigates the fracture permeability of granite reservoirs in the South China Sea, introducing an enhanced evaluation model for planar fracture permeability based on Darcy’s law and Poiseuille’s law. The model incorporates factors such as fracture heterogeneity, tortuosity, angle, and aperture to improve permeability assessments. Building on a single-fracture model, this research integrates mass transfer equations and trigonometric functions to assess intersecting fractures’ permeability. Numerical simulations explore how tortuosity, angle, and aperture affect individual fracture permeability and the influence of relative positioning in intersecting fractures. The model makes key assumptions, including minimal consideration of horizontal stress and the assumption of unidirectional laminar flow in cross-fractures. Granite outcrop samples were systematically collected, followed by full-diameter core drilling. A range of planar models with varying fracture apertures were designed, and permeability measurements were conducted using the AU-TOSCAN-II multifunctional core scanner with a steady-state gas injection method. The results showed consistency between the improved model and experimental findings regarding the effects of fracture aperture and angle on permeability, confirming the model’s accuracy in reflecting the fractures’ influence on reservoir flow capacity. For intersecting fractures, a comparative analysis of core X-ray computed tomography (X-CT) scanning results and experimental outcomes highlighted discrepancies between actual permeability measurements and theoretical simulations based on tortuosity and aperture variations. Limitations exist, particularly for cross-fractures, where quantifying complexity is challenging, leading to potential discrepancies between simulation and experimental results. Further comparisons between core experiments and logging responses are necessary for model refinement. In response to the challenges associated with evaluating absolute permeability in fractured reservoirs, this study presents a novel theoretical assessment model that considers both single and intersecting fractures. The model’s validity is demonstrated through actual core experiments, confirming the effectiveness of the single-fracture model while highlighting the need for further refinement of the dual-fracture model. The findings provide scientific support for the exploration and development of granite reservoirs in the South China Sea and establish a foundation for permeability predictions in other complex fractured reservoir systems, thereby advancing the field of fracture permeability assessment.

Characterization and Inversion Method of Relative Permeability of Emulsion Flooding.

Relative permeability curves are one of the crucial factors that control the behavior of multiphase flow in petroleum reservoirs. Accurate prediction of the relative permeability curve involving emulsification and emulsion transport in emulsion flooding is vital to enhancing heavy oil recovery. In this study, a relative permeability characterization model including the emulsification mechanism and emulsion transport is developed, in which residual oil saturation and end-point permeability for water are parametrized as functions of emulsion concentration and capillary number. Based on the built characterization model, an inversion method (ensemble Kalman filter) is used to estimate the relative permeability curves of emulsion flooding. The inversion results of four sets of emulsion flooding experiments show that the errors of end points between the Johnson-Bossler-Neumann method and inversion method are less than 10%. For the continuous emulsification process in the in situ emulsion flooding tests, the inversed relative permeability curves shift between the upper and the inferior limits of the permeability. The error of residual oil saturation between the inversion and the experiment is less than 10%. In summary, this study demonstrates the feasibility of using the characterization model and inversion method to infer the relative permeability curves of emulsion flooding, which can aid in the predictions of multiphase flow in heavy oil reservoirs.

Techno-economic optimization of enhanced geothermal systems with multi-well fractured reservoirs via geothermal economic ratio

Enhanced Geothermal System (EGS) shows vast potential for exploiting deep geothermal energy sources, although its techno-economic feasibility remains uncertain. The current research challenge lies in the absence of a reliable tool to rapidly evaluate the economic gains associated with the design of geothermal reservoirs. This study aims to develop an evaluation metric to assess the geothermal economic ratio of EGS. The efficacy, practicality, and simplicity of the proposed metric were demonstrated through its application to reservoir cases involving six fracture structures and four influencing parameters. The geothermal economic ratio of the system was enhanced through the augmentation of injection mass and the expansion of production well spacing. However, it was reduced by higher injection temperatures and wider primary fracture apertures. Using response surface design, the optimal parameters were found to be an injection temperature of 24 °C, an injection mass of 30 kg/s, a primary fracture aperture of 6.192 mm, and a production well spacing of 200 m. These parameters facilitated a reservoir heating efficiency of 0.322, a reservoir flow efficiency of 0.514, and a geothermal economic ratio of 1.026 × 10−20. The proposed metric and results would offer a concise and informative analysis of the market potential of EGS.

Numerical simulation of two-phase oil–water flow in fractured-vuggy reservoirs based on the coefficient of porous medium proportion and coupled regions

Based on the flow characteristics of fluids in various reservoir media, fractured-vuggy oil reservoirs can be classified into seepage zones and conduit flow zones. An interface exists between these two regions, where the movement of formation fluid near this interface is characterized by a coupling or transitional phenomenon between seepage and conduit flow. However, the complexity of this coupling interface poses challenges for traditional numerical simulations in accurately representing the intricate fluid dynamics within fractured-vuggy oil reservoirs. This limitation impacts the development planning and production adjustment strategies for fractured-vuggy oil reservoirs. Consequently, achieving accurate characterization and numerical simulation of these systems remains a critical challenge that requires urgent attention. A new mathematical model for oil-water two-phase flow in fractured-vuggy oil reservoirs is presented, which developed based on a novel coupling method. The model introduces the concept of the proportion coefficient of porous media within unit grids and defines a coupling region. It employs an enhanced Stokes–Brinkman equation to address the coupling issue by incorporating the proportion coefficient of porous media, thereby facilitating a more accurate description of the coupling interface through the use of the coupling region. Additionally, this proportion coefficient characterizes the unfilled cave boundary, simplifying the representation of model boundary conditions. The secondary development on the open-source fluid dynamics software is conducted by using matrix & laboratory (MATLAB). The governing equations of the mathematical model are discretized utilizing finite volume methods and applying staggered grid techniques along with a semi-implicit calculation format for pressure coupling—the Semi-Implicit Method for Pressure Linked Equations algorithm—to solve for both pressure and velocity fields. Under identical mechanism models, comparisons between simulation results from this two-phase flow program and those obtained from Eclipse reveal that our program demonstrates superior performance in accurately depicting flow states within unfilled caves, thus validating its numerical simulation outcomes for two-phase flow in fractured cave reservoirs. Utilizing the S48 fault-dipole unit as a case study, this research conducted numerical simulations to investigate the water-in-place (WIP) behavior in fractured-vuggy oil reservoirs. The primary focus was on analyzing the upward trend of WIP and its influencing factors during production across various combinations of fractures and dipoles, thereby validating the feasibility of the numerical modeling approach in real-world reservoirs. The simulation results indicated that when multiple dissolution cavities at different locations communicated with the well bottom sequentially, the WIP in the production well exhibited a staircase-like increase. Furthermore, as the distance between bottom water and well bottom increased, its effect on water intrusion into the well diminished, leading to a slower variation in the WIP curve. These characteristics manifested as sudden influxes of water flooding, rapid increases in water levels, and gradual rises—all consistent with actual field production observations. The newly established numerical simulation method for fractured-vuggy oil reservoirs quantitatively describes two-phase flow dynamics within these systems, thus effectively predicting their production behaviors and providing guidance aimed at enhancing recovery rates typically observed in fractured-vuggy oil reservoirs.

Micro-scale flow simulation study of low-yield wells in tight gas reservoirs

Abstract The mechanism of gas-water flow in reservoirs has traditionally been characterized macroscopically based on flow experiments, but the microscopic mechanisms of gas-water flow in porous media cannot be precisely described experimentally. This paper categorizes low-yield gas wells into Types I, II, and III. With microscopic visualization principles, three different types of core thin-section photos were selected to construct a pore structure model, allowing for micro-scale flow simulation to examine micro-scale percolation patterns in various types of low-yield gas well reservoirs. The results show that there is a shorter displacement time in Type I reservoirs compared to Type II and III reservoirs which exhibit more pronounced fingering phenomena.

Studying the impact of pore sizes on gas flow and distribution in volatile carbonate reservoirs using a new triple-porosity model

Studying the impact of pore sizes on gas flow and distribution in volatile carbonate reservoirs using a new triple-porosity model

Underpinnings of reservoir and techno-economic analysis for Himalayan and Son-Narmada-Tapti geothermal sites of India

The high capital cost and risks associated with the extraction process of geothermal energy are key factors in the project economics. This paper presents a comprehensive technoeconomic study based on reservoir heat and flow simulations along with the levelized cost of energy (LCOE) for two geothermal sites (Himalayan and Son-Narmada-Tapti i.e. SONATA) in India.Dual porosity reservoir simulation models were constructed and were used to obtain the cumulative and the dynamic thermal energy potentials of these sites. The simulation studies suggest that both sites are equally potent for geothermal energy extraction. Comparatively, the proven cumulative energy potentials for the Himalayan and SONATA sites are found to be 4.92–5.10 and 3.62–3.7 TW h, respectively, for the 30 years of production at a rate of 92 kg/s. This difference can be attributed mainly to higher temperatures and deeper sites at the Himalayan Province. Sensitivity analyses were conducted to assess the impact of various parameters, including porosity, permeability, fracture spacing, and thermal conductivity. The results suggest that porosity and permeability are the key enablers of efficient energy production. The economic feasibility study suggests that the LCOE costs are high for these sites ($148/MWh for the Himalayan and $137/MWh for the SONATA). These two sites have CO2 mitigation potential in the range of 3.12 and 11.36 Megatons from a single doublet well configuration considering the CO2 emissions from conventional coal-fired thermal power plants. Overall, SONATA can be the better prospect considering the logistics and operational challenges along with reservoir heat potential.

Optimal operation model of ecological flow of hydropower station based on genetic algorithm and neural network

Amid diverse water demands, the conflict between ecological flow adjustments and power generation flow adjustments in hydropower station water resource dispatching, coupled with an increasing diversity of constraints, complicates the issue of water resource optimization and dispatching. How to scientifically develop feedback regulation mechanisms to promote a virtuous ecological cycle, fine tune existing hydropower station scheduling plans, and achieve multi-objective optimization scheduling is the core issue in researching the comprehensive utilization of water resources. This study establishes a reservoir flow regulation model with the objective functions of maximizing power generation and achieving optimal average ecological protection. The model, constrained by water balance, reservoir capacity, unit output, and unit overflow, was optimized and solved using the genetic algorithm-backpropagation neural network (GA-BPNN) approach. This study establishes a reservoir flow regulation model with the GA-BPNN algorithm was applied in multi-objective optimization to identify an optimal solution that maximizes overall system performance while adhering to ecological flow constraints. The results indicate that the optimized plan has performed effectively in hydropower station operations. It not only satisfies ecological flow requirements, but also significantly enhances power generation efficiency. Specifically, power generation increased by 32,680 kw·h, a 23.85% growth rate. The optimized plan significantly enhances the comprehensive utilization efficiency of water resources. It offers a scientific basis for the rational planning, dispatching and utilization of water resources in hydropower stations and reservoirs.

Research on Refined Water Injection Technology for Medium and High Water Cut Reservoirs in Nanpu 4 Block

Abstract For water injection development reservoir, the key is to control the di-rection and flow field of the injected water in the reservoir to adjust the tapping of the remaining oil between wells. This paper presents that, by applying the comprehensive discrimination technique of inefficient cir-culation flow field, a flow field evaluation model containing permeabil-ity, overwater multiplier and water saturation seepage characteristics parameters is established and the small layer flow field distribution is quantitatively evaluated by numerical simulation. Based on the geo-logical characteristics, development characteristics and grid inefficient circulation coefficients, the flow field is qualitatively classified into three types: streamline not established, streamline primary and sec-ondary, and streamline fixed and difficult to adjust. Based on the re-search of domestic and foreign literature and numerical simulation, the management system of different types of flow fields is studied to clari-fy the reasonable development technology policy of reservoir flow field adjustment and tapping the remaining oil between wells, so as to achieve the purpose of controlling the reservoir water content rise rate, reducing the water content rate and improving the recovery rate. The mine field experiments conducted in Nanpu 4 block showed that the recovery rate of the block increased by 4 percentage points, indicating that the block development achieved significant results. This is an im-portant guideline for reservoir development in low recovery, medium to high water-bearing reservoirs with water injection development.

Normal fault architecture, evolution, and deformation mechanisms in basalts, Húsavik, Iceland: Impact on fluid flow in geothermal reservoirs and seismicity

Faults within layered basaltic sequences significantly influence hydrothermal fluid flow in shallow geothermal reservoirs and potentially during CO2 sequestration and storage. Nevertheless, their characterization regarding fault zone architecture, fluid flow, deformation mechanisms, and seismic potential remains underdeveloped. This study addresses this gap by integrating structural and microstructural observations with X-ray diffraction analyses of exposed normal-transtensional faults associated with the seismically active Húsavík-Flatey Fault in the Tjörnes Fracture Zone, Northern Iceland. Our findings demonstrate that the evolution of basalt-hosted normal-transtensional faults progresses through distinct stages: (1) low-displacement fault propagation from pre-existing cooling joints; (2) fault linkage via dilational jogs; (3) damage zone/fault core growth through brecciation and cataclastic processes; (4) shear localization along sharp slip surfaces; and (5) smearing of volcaniclastic interbeds along the principal fault plane. Evidence of shear localization, truncated clasts, and hydrothermal breccias/veins suggests repeated seismic slip events facilitated by overpressured fluids. Conversely, the presence of clay-rich foliated cataclasite indicates aseismic slips during interseismic periods. Slip along fault jogs, bends, geometric irregularities, and orientation changes causes the dilatant opening of the fault planes and extensional horsetail fractures at fault tips. These structures create main tabular zones for lateral movement of hydrothermal fluids parallel to the fault strike in shallow geothermal reservoirs situated in active extensional-transtensional tectonic settings. In addition, the dilational jogs and the intersection of horsetail veins with the hosting faults may define linear zones of high structural permeability and intense localized fluid flow parallel to the σ2 paleostress orientation and finally mineral precipitation. The results of this study can be utilized to improve models of geothermal fluid flow for enhanced recovery in basaltic reservoirs and assess seismic risk in basaltic faults.

Enhancing geothermal efficiency: Experimental evaluation of a high-temperature preformed particle gel for controlling preferential fluid flow

Enhanced Geothermal System (EGS) reservoirs represent a vital frontier in clean energy production. However, short-circulation flow within these reservoirs can significantly affect their immediate efficiency and long-term viability. Injected cold fluids moving through wide fractures or direct channels between injection and production wells reduce thermal production temperatures, disrupting energy output. Preformed Particle Gels (PPGs) have proven effective in controlling preferential fluid flow in oil and gas reservoirs, effectively regulating fluid movement. This work explores the potential of a novel High-Temperature Preformed Particle Gel (HT-PPG), designed for geothermal applications, to plug fractures in a simulated geothermal reservoir. Core flooding experiments in coated and uncoated sandstone models were conducted under varying HT-PPG sizes, swelling ratios, and fracture widths to determine gel plugging efficiency. Variations in the HT-PPG injection pressure, breakthrough pressure, and residual resistance factor (Frr) were evaluated. Water breakthrough pressures can reach 464.10 psi/ft. While the stable injection pressure of HT-PPG decreased with increasing swelling ratio and fracture width, it was higher in uncoated cores. The HT-PPG significantly sealed the fractures, drastically reducing conductivities to millidarcy levels. This work validates HT-PPG a robust solution to mitigate fluid diversion challenges in sandstone EGS reservoirs, enhancing performance and advancing sustainable geothermal energy production.

Numerical Simulation of Shale Gas Flow in Non-Conventional Reservoirs Using the OpenACC API

Numerical Simulation of Shale Gas Flow in Non-Conventional Reservoirs Using the OpenACC API

Structural controls on hydrothermal fluid flow in a carbonate geothermal reservoir: Insights from giant carbonate veins in western Germany

This study examines the impact of polyphase tectonics on the development of structurally controlled hydrothermal fluid pathways in carbonate geothermal reservoirs. Our case study focuses on hydrothermal carbonate veins and vein-filled faults in Devonian carbonates from the North Rhine-Westphalia region in western Germany, currently being explored as a potential low-enthalpy geothermal reservoir at depths of 4–5 km. These veins, which can be up to 20 m thick, are subvertical and strike NNW, N, or ESE. They exhibit pinch-and-swell undulating geometries, faulted vein-wall contacts, and occasional fillings of hydrothermal breccias. Vein-filled normal faults show hybrid shear-dilatant openings, with fault tips characterized by horsetail vein terminations. The textures, orientations, and age of the veins suggest their formation at low confining pressures and at depths < 2 km during the Post-Variscan East-West extension. Orthogonal North- and East-striking strike slip faults, inherited from the Variscan orogeny, were likely reactivated during post-Variscan extension, with a significant dilatant component that formed the observed veins. In the Ruhr Basin, the dilation tendency analysis indicates that NNW-striking veins or joints are optimally oriented for re-opening under the current strike-slip stress regime, characterized by NNW-trending maximum horizontal stress. The intersections of fractures may currently create moderately SSE-plunging linear zones of enhanced fluid flow. The main uncertainty regards the presence of similar structures at geothermal reservoir depths of ∼4–5 km in the Middle Devonian carbonates underneath the Ruhr Basin. As the study veins are likely to have formed at depths <2 km, the existence of analogous dilatant conduits at greater depths remains speculative. Eventually, we propose that zones characterized by open discontinuities and channelized fluid flow in carbonate geothermal reservoir in strike-slip tectonic settings can be: (a) dilational jogs between overlapping strike-slip faults, (b) bends along faults, and (c) strike-slip fault terminations with horsetail extensional structures. These zones can also be prone to enhanced karstification.