Fracture Permeability Research Articles

Modeling microwave heating for enhanced shale gas recovery: Fully coupled two-phase flows with heat transfer and electromagnetism in deformable reservoirs

To investigate the mechanisms of fluid migration during shale gas extraction under microwave irradiation, we developed a coupled Electromagnetic-Thermal-Hydraulic-Mechanical (ETHM) model. This model accounts for changes in fracture permeability due to variations in temperature, gas pressure, and methane desorption. The impact of microwave power on both gas production and the alteration of reservoir geological properties under microwave stimulation was investigated. Simulation results revealed that with a microwave injection power of 4,000 W, cumulative gas production increased by 45 %, reaching 64.9 million cubic meters. Additionally, the influence of initial water saturation and the diffusion damping coefficient on both gas and water production was examined. The findings show that cumulative water production was 33 % higher when microwave heating was applied compared to scenarios without microwave stimulation. An increase in initial water saturation led to a decrease in daily gas production during the early stages of extraction. Under microwave irradiation, the methane adsorption capacity at data acquisition point MP2 decreased to 0.0075 m3/kg, representing a 69 % reduction compared to conditions without microwave stimulation. Our analysis also found that daily gas production is highly sensitive to the diffusion damping coefficient. The diffusion attenuation effect had a notably negative impact on improving the recovery rate of shale gas reservoirs. In a word, this research holds significant implications for understanding the trends in gas and water production as well as the sensitivity of geological parameters during microwave-assisted thermal recovery of shale gas.

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.

New correlations to estimate the rough fracture permeability using computational fluid dynamics simulation

In fractured reservoirs, the fracture network provides the main path for fluid flow. Appropriate estimation of the fracture permeability influences the precise prediction of the reservoir’s future performance. Commonly, for a known geometry of natural or induced fracture, the permeability is estimated by applying local cubic law. One major drawback of this approach is that the fracture surface roughness, which has a significant effect on fracture permeability, is not considered. Moreover, the knowledge about the impact of fracture surface roughness on fracture permeability is not currently sufficient. In this research, the fluid flow in fractures with rough-walled surfaces was studied using computational fluid dynamics. For this purpose, the fluid flow through fractures was simulated by applying appropriate roughness for fracture walls. Furthermore, two correlations, based on response surface methodology and power-law models, were proposed to predict fracture permeability as a function of four independent variables (surface roughness, fracture aperture, angle, and porosity). The results of the two presented correlations were validated, and the statistical analysis indicates that both models are appropriate to predict fracture permeability. The findings of this study will be of great assistance with understanding and characterization of the fluid flow in rough fractures and can be used in future works.

Investigating the interplay of fracture inclination and rock properties on supercritical CO2-foam flow in porous media

Natural and induced fractures in porous media pose significant challenges in subsurface applications such as carbon storage, hydrocarbon production, and aquifer contamination mitigation. These highly permeable fractures disrupt the natural flow in porous formations, leading to issues including reduced pressure buildup and early fluid breakthrough. To address these challenges, foam injection serves as an effective method for fluid diversion, offering enhanced mobility control in fractured media. However, the foam's performance must be carefully optimized considering factors such as reservoir conditions, in-situ fluid compatibility, rock properties like pore structure, permeability, and mineralogy, as well as fracture roughness, homogeneity, and orientation. This study investigates the effects of inclination angles (0°, 5°, 10°, and 15°) of smooth, saw-cut fractures on the performance of supercritical carbon dioxide foam in three distinct carbonate rocks: Indiana limestone, Fond Du Lac dolomite, and Alabama Silver limestone. These rocks exhibit a wide range of permeabilities, from 0.4 mD to 5.4 D. The findings are compared with previous research on Berea sandstone. It is demonstrated that optimal foam performance is more readily achieved in fractured porous media with higher permeability, larger pore throat sizes, and mineralogically compatible formations. Unlike previous work where studies focused on the individual impact of specific parameters, including a previous study conducted by our group to explore the effect of fracture orientation, the novelty of this paper is that it addresses multiple parameters at the same time and the interconnected roles that they play. This interplay of fracture orientation, rock type, and flow properties is what determines the ideal conditions that must be optimized to achieve the required foam performance.

Optimizing fracturing techniques for enhanced hydrate dissociation in low-permeability reservoirs: Insights from numerical simulation

Natural gas hydrate represents an environmentally friendly alternative energy. However, the low-permeability hydrate reservoirs pose significant challenges to commercial production. To optimize hydrate production, reservoir stimulation methods like hydraulic fracturing, gas fracturing, and explosive fracturing are potential. In the investigation of the fracturing effect on hydrate dissociation behavior, we developed a three-dimensional model that comprehensively incorporates the arrangement of fracture planes, encompassing fracture permeability, spacing, and height. The model was implemented using a self-developed hydrate simulator which was validated at multiple scales. We firstly conducted a comparative analysis, contrasting the conventional depressurization method in horizontal wells with a combined depressurization and fracturing method. The comparison suggested that fracturing brings significant promotion (113.5%) on hydrate dissociation. Sensitivity analysis revealed fracture permeability and fracture height evidently exhibit an optimal value that facilitates the dissociation behavior. The optimal value of fracture permeability is dependent on the geological background. The optimal value of fracture height occurs just before penetrating the hydrate-bearing sediment layer and the overlying/underlying formations, i.e., near the thickness of the hydrate-bearing sediment layer. The impact of spacing on gas volume is limited while decreasing the spacing leads to more evident localized dissociation and differential subsidence of hydrate reservoir. It is necessary to balance production and geological risks when selecting the fracture spacing. The conclusions suggest that the fracturing operation need to be optimized by controlling the injection rate and the fracturing interval. It is not advisable to blindly pursue the effectiveness of reservoir stimulation but rather to consider the geological conditions. Additionally, we have found that it is preferable to establish barriers between the reservoir and overlying/underlying formations near the hydraulic fracturing section before reservoir stimulation, to prevent excessive early water production. In conclusion, this study would provide valuable insights for the optimization of fracturing techniques in stimulation of hydrate reservoir.

Evolution law of pulsating seepage and thermal deformation by injecting high‐temperature steam into coal for thermal coalbed methane recovery

AbstractChinese coal reservoirs are characterized by low pressure and low permeability, which need to be enhanced so as to increase production. However, conventional methods for permeability enhancement can only increase the permeability in fractures, but not the ultra‐low permeability in coal matrices. Attempts to enhance such impermeable structures lead to rapid attenuation of gas production, especially in the late stage of gas extraction. Thermal stimulation by injecting high‐temperature steam is a promising method to increase gas production. The critical scientific challenges that still hinder its widespread application are related to the evolution law of permeability of high‐temperature steam in coal and the thermal deformation of coal. In this study, an experimental approach is developed to explore the high‐temperature steam seepage coupled with the thermal deformation in coal under triaxial stress. The tests were conducted using cylindrical coal specimens of ϕ50 mm × 100 mm. The permeability and thermal strain in coal were investigated when high‐temperature steam was injected at 151.11, 183.20, 213.65, and 239.76°C. The experimental results reveal for the first time that as the amount of injected fluid increases, the steam permeability shows periodic pulsation changes. This paper introduces and explains the main traits of this discovery that may shed more light on the seepage phenomenon. When the injected steam temperature increases, the amplitude of pulsating permeability decreases, whereas the frequency increases; meanwhile, the period becomes shorter, the pulsation peak appears earlier, and the stabilization time becomes longer. The average peak permeability shows a “U‐shaped” trend, decreasing first and then increasing as the steam temperature increases. Meanwhile, with the extension of steam injection time, the axial, radial, and volumetric strains of coal show a stage‐wise expansion characteristic at different temperatures of steam injection, except for the radial strains at 151.11°C. A two‐phase flow theory of gas–liquid is adopted to elucidate the mechanism of pulsating seepage of steam. Moreover, the influencing mechanism of inward and outward thermal expansion on the permeability of coal is interpreted. The results presented in this paper provide new insight into the feasibility of thermal gas recovery by steam injection.

The influence of hydraulic fracture and reservoir parameters on the storage of CO2 and enhancing CH4 recovery in Yanchang formation

The demand for a clean energy source from shale is growing day-to-day since it is not harmful to the environment like other fossil fuels. Further, shale reservoirs offer long-term geo-carbon dioxide (CO2) storage. Innovations in horizontal drilling and multi-stage hydraulic fracturing have made shale gas extraction and geo-CO2 storage economically viable. A three-dimensional Yanchang shale formation simulation model in Ordos's basin was developed using CMG-GEM, considering adsorption/desorption, diffusion, geomechanics, permeability changes, and non-Darcy flow. Two horizontally drilled wells, each 510 m long, were fractured and positioned 90 m apart. CO2 gas was injected into Well-2, producing methane (CH4) in Well-1. After simulation for 30 years, the cumulative mass of CH4 produced was 1.07×10+5kg, the cumulative mass of CO2 produced was 2.3×10+4kg, which is 1.14% of the mass injected, the cumulative mass of CO2 injected was 2.01×10+6kg and cumulative mass of CO2 gas stored was 1.987×10+6kg which is 98.86% of the injected mass of CO2 gas. The natural fracture system was the dominant factor of enhanced shale gas recovery and CO2 injection in the Yanchang shale formation. A sensitivity analysis was conducted with CMG-CMOST, examining the influence of reservoir and hydraulic fracture parameters in the storage of CO2 and enhancing CH4 recovery. Natural fracture porosity had the most significant impact on CH4 production and CO2 storage, followed by fracture permeability and half-length leading for hydraulic fracture parameters, with fracture conductivity being the least influential parameter. The approach used in this study applies to tight shale oil and gas formations in various sedimentary basins worldwide, enabling a more comprehensive understanding of reservoirs and hydraulic fracture parameters that can enhance oil and natural gas production.

Analysis of fractures generated by faults at micro- and macro-scale and the influence on the secondary permeability: application to the Nevado del Ruiz area (Colombia)

This research contributes to the knowledge of the geothermal area of the Nevado del Ruiz Volcano (Colombia) by analyzing the secondary permeability and connectivity of fractures at microstructural and macrostructural level. Although the Nevado del Ruiz Volcano (NRV) area has had geothermal exploration studies for power generation since 1968, there is still no exploitation of its geothermal resources. The NRV geothermal reservoir is characterized by a low primary permeability and the presence of several geological faults crossing a tectonically active and complex region. The analysis was performed comparing a zone affected by intense faulting with another one characterized by the same lithology, but with less influence of faulting and located further from the volcano. Fractures were characterized at outcrops with the window sampling method, and petrographic analysis was performed to confirm the mineralogy of samples collected. At the microstructural scale it was found that faulting does not necessarily influence the interconnectivity of fractures, but it does influence their intensity, quantity, and strike. To analyze the influence of fractures on groundwater flow, it is suggested to consider three main aspects: secondary permeability, connectivity, and fracture intensity. The lithology of major geothermal interest in the NVR area (Pes) presented greater connectivity and fracture intensity, which, combined with the high foliation observed in field, increase its effective permeability. The secondary permeability of different lithologies in the NRV area ranged between 1.15 × 10–6 and 10.32 × 10–7 m2. Most of the hot springs were in areas of high macrostructural connectivity, supporting the idea that groundwater flow is dominated by the secondary permeability of rocks. Estimation of the secondary permeability and identification of areas of high fracturing and connectivity, contributes to the understanding of the NRV geothermal area, which is a key aspect when drilling for successful well production. The methodology presented is useful in the initial exploration phase in fractured geothermal reservoirs.

Fluid flow and solute transport simulations in tight geologic formations: Discrete fracture network and continuous time random walk analyses

Understanding the effect of fracture network heterogeneity on flow and transport in tight formations with low permeability values is of great importance in a wide variety of applications, such as groundwater pollution and storage as well as water production. Although numerous studies have investigated solute transport in fractured media, investigation about scale effects on flow and transport in low-permeability aquifers is limited. More specifically, we are not aware of any study that has addressed how the continuous time random walk (CTRW) model parameters vary with scale and fracture network properties. To this end, we performed a set of numerical simulations in sparse fracture networks of sizes L = 20, 35, and 50 m under two different volumetric fracture counts (p30 = 0.05 and 0.1) using the discrete fracture network approach. The fractures in the networks were elliptical in shape, and their radii followed a truncated power-law distribution with exponents α = 1.5, 2, and 2.5. We simulated fluid flow using the Reynolds equation, and solute transport was simulated using particle tracking. The solute transport behavior was quantified by fitting the solution of the CTRW transport equation to the arrival time distributions. Results showed that as the truncated power law exponent α increased, the permeability of the networks decreased. In all the fracture networks studied, we found non-Fickian solute transport behavior deduced from small values of β(0.69≤β≤1.25), the exponent in the truncated power-law arrival time distribution in the CTRW model. In our fracture networks, the aperture size spanned less than one order of magnitude meaning that the fracture permeability distribution was relatively narrow. Therefore, the observed non-Fickian behavior should be attributed to sparse fracture networks and low connectivity. We found that the effective permeability, keff, at p30 = 0.05 was more scale-dependent compared to that at p30 = 0.1 because the fracture networks with p30 = 0.05 were less connected and, thus, more heterogeneous. Our simulation also disclosed the scale dependence of the CTRW model parameters. We conducted multiple linear regression analysis to link the CTRW model parameters to the network size as well as the geometrical and topological properties of the network. Results of regression analysis showed that all the CTRW model parameters except the average solute velocity were significantly dependent on the system size L (p-value < 0.05). Further investigations using a broader range of fracture network properties, such as broader aperture size distributions, smaller and larger network sizes and volumetric fracture counts are still required.

A Comprehensive Investigation of the Relationship between Fractures and Oil Production in a Giant Fractured Carbonate Field

This study examines the connections between various fracture indicators and production data with an example from one of the giant fields in the Middle East producing complex fractured carbonate lithologies. The field under study hosts two reservoirs with a long development and production history, including carbonates from the Asmari and Bangestan Formations. A fracture intensity map was generated based on the interpretation of image logs from 28 wells drilled within the field. Mud loss data were collected and mapped based on the geostatistical Gaussian Random Function Simulation (GRFS) algorithm. Maximum curvature maps were generated based on Asmari structural surface maps. Comparing the results shows a good agreement between the curvature map, fault distribution model, mud loss map, fracture intensity map, and productivity index. The results of image log interpretations led to the identification of four classes of open fractures, including major open fractures, medium open fractures, minor open fractures, and hairline fractures. Using the azimuth and dip data of the four fracture sets mentioned above, the fracture intensity log was generated as a continuous log for each well with available image log data. For this purpose, the fracture intensity log and a continuous fracture network (CFN) model were generated. The continuous fracture network model was used to generate a 3D discrete fracture network (DFN) for the Asmari Formation. Finally, a 3D upscaled model of fracture dip and azimuth, fracture porosity, fracture permeability, fracture length, fracture aperture, and the sigma parameter (the connectivity index between matrix and fracture) were obtained. The results of this study can illuminate the modeling of intricate reservoirs and the associated production challenges, providing insights not only during the initial production phase but also in the application of advanced oil recovery methods, such as thermal recovery.

Simulation of two-phase flow in 3D fractured reservoirs using a projection-based Embedded Discrete Fracture Model on Unstructured tetrahedral grids (pEDFM-U)

The modeling of fluid flow in heterogeneous, anisotropic and fractured porous media is relevant in many applications, including hydrocarbon and groundwater extraction, dispersion of contaminants, hydrogen or carbon dioxide (CO2) storage. Thus, accurate and scalable simulation of fluid flow through these formations continues to be a great challenge. The presence of fractures that are explicitly modeled, ranging from flow barriers to highly conductive channels, significantly increases the complexity of the numerical simulation. The Embedded Discrete Fracture Model (EDFM) produces results that can be as accurate as those obtained using equidimensional Discrete Fracture Models (DFM) at a much lower computational cost for highly conductive fractures, but it is not adequate for impermeable barriers. In contrast, the pEDFM (projection-based Embedded Discrete Fracture Model) produces accurate results for both, channels and barriers by using additional matrix-fracture connectivities. In its current versions, it is restricted to cartesian and corner-point grid geometries and to the classical Two Point Flux Approximation (TPFA) scheme. In this work, for the first time, the pEDFM is extended to handle unstructured tetrahedral meshes (pEDFM-U). In addition, interface fluxes are approximated by using the Multipoint Flux Approximation method with a Diamond stencil (MPFA-D). This allows for simulation of highly heterogeneous and anisotropic geo-models. The developed method is robust and can deal with full permeability tensors on arbitrary tetrahedral meshes. The advective terms are discretized considering an implicit First Order Upwind (FOU) method. Our method is implemented within the DARSim (Delft Advanced Reservoir Simulation) open-source simulator framework. Through several test cases, the proposed method showed to be robust and capable to accurately capture the effects of both high and low permeability fractures for general tetrahedral meshes, under arbitrary heterogeneous and anisotropic permeability tensors for the rock matrix.

Influence of non-intersecting cemented natural fractures on hydraulic fracture propagation behavior

Fractures in deeply buried or formerly deeply buried rocks commonly contain mineral deposits having varying degrees of strength. Understanding how cement deposits in fractures interact with hydraulic fractures (HFs) is important for hydraulic fracture design for practical engineering applications such as enhanced geothermal fluid circulation or oil and gas production. Using discrete element methods, we describe a fully fluid-solid coupling numerical model simulating hydraulic fracture propagation to investigate the influence of cemented natural fractures (CNFs) that do not intersect the predicted path of hydraulic fractures on HF propagation morphology. The fracture morphology depicted by the numerical model aligns well with analytical solutions, indicating the reliability of the simulation results. Using this model, we delved into the effects of fracture cement strength and position, fracturing fluid viscosity, and induced stress field on the interactive propagation patterns of fractures. The simulation results indicate that the HF is captured by weakly non-intersecting CNF, causing the activation of the CNF and the development of cracks primarily caused by tensile failure. As the HF approaches the CNF, the induced tensile stress region at the fracture tip offsets toward the CNF, resulting in fracture reorientation. When the cementing strength ratio between pre-existing natural fracture and reservoir matrix is less than 0.5, it is beneficial to activate CNF and enhance reservoir permeability. The seepage of low-viscosity fracturing fluid into the reservoir significantly enhances the ability of the HF and non-intersecting CNF to communicate with each other, thereby providing favorable pathways for oil and gas flow. The research findings offer valuable insights into fracture network connectivity and permeability enhancement, contributing to enhanced reservoir stimulation strategies.

A Generalized Method for Dynamic Fracture Characterization Using Two-Phase Rate Transient Analysis of Flowback and Production Data

Summary This study presents a comprehensive method for characterizing reservoir properties and hydraulic fracture (HF) closure dynamics using the rate transient analysis of flowback and production data. The proposed method includes straightline analysis (SLA), type-curve analysis (TCA), and model history matching (MHM), which are developed for scenarios of two-phase flow in fracture, stimulated reservoir volume (SRV), and nonstimulated reservoir volume (NSRV) domains. HF closure dynamics are characterized by two key parameters, which are pressure-dependent permeability and porosity controlled by fracture permeability modulus and compressibility. The above techniques are combined into a generalized workflow to estimate iteratively the five parameters (including four optional parameters and one fixed parameter) by reconciling data in different domains of time (single-phase water flow, two-phase flow, and hydrocarbon-dominated flow), analysis methods (SLA, TCA, and MHM), and phases (water and hydrocarbon phase). We used flowback and production data from a shale gas well in the US and a shale oil well in China to verify the practicability of the method. The analysis results of the field cases confirm the good performance of the newly developed comprehensive method and verify the accuracy in estimating the static fracture properties [initial fracture pore volume (PV) and permeability] and the HF dynamic parameters using the proposed generalized workflow. The accurate prediction of the decreasing fracture permeability and porosity, fracture permeability modulus, and compressibility demonstrates the applicability of the comprehensive method in quantifying HF dynamics. The field application results suggest a reduction of the fracture PV by 15% and 20%, and a reduction of the fracture permeability by 80% and 90% for shale gas and shale oil wells, respectively.

Investigating rough single-fracture permeabilities with persistent homology

Abstract. The permeability of rock fractures is a crucial parameter for flow processes in the subsurface. In the last few decades, different methods were developed to investigate on permeability in fractures, such as flow-through experiments, numerical flow simulations, or empirical equations. In recent years, the topological method of persistent homology was also used to estimate the permeability of fracture networks and porous rocks but not for rough single fractures yet. Hence, we apply persistent homology analysis on a decimetre-scale, rough sandstone bedding joint. To investigate the influence of roughness, three different data sets are created to perform the analysis: (1) 200 µm, (2) 100 µm, and (3) 50 µm resolutions. All estimated permeabilities were then compared to values derived by experimental air permeameter measurements and numerical flow simulation. The results reveal that persistent homology analysis is able to estimate the permeability of a single fracture, even if it tends to slightly overestimate permeabilities compared to conventional methods. Previous studies using porous media showed the same overestimation trend. Furthermore, the expenditure of time for persistent homology analysis, as well as air permeameter measurements and numerical flow simulation, was compared, which showed that persistent homology analysis can be also an acceptable alternative method.

Development status and research recommendations for thermal extraction technology in deep hot dry rock reservoirs

AbstractBased on a comprehensive review of domestic and foreign literature, this article discusses the technical difficulties and development status of enhanced geothermal system (EGS) concerning the thermal energy extraction of deep hot dry rock (HDR) reservoirs and proposes suggestions for the research focus of numerical simulation of HDR reservoir stimulation. Additionally, it summarizes the existing methods and mainstream working fluids for HDR reservoir stimulation. The article emphasizes the significance of factors such as well location, production well depth, artificial fracture orientation, and complexity in optimizing the thermal production efficiency of the EGS. Furthermore, this article delves into a detailed discussion on the influence of fracture spacing, fracture permeability, fracture length, fluid injection rate, and injected fluid temperature on the performance of the EGS. In light of the thermo‐hydro‐mechanical coupling challenges associated with high‐temperature reservoirs, it is suggested that future research efforts should focus on investigating the impact of thermo‐induced stresses on the stability of the artificial fracture network within the EGS during long‐term (&gt;30 years) circulation of hot and cold fluids.

Investigation of REV scale and anisotropy for 2D permeable fracture Networks: The role of geological entropy

To investigate the intrinsic association between geometrical properties and permeability of anisotropic fractured media, a methodology of geological entropy is applied to anisotropic fracture networks for the evaluation of seepage fields. By integrating the synthetic effect of fracture geometrical parameters (e.g., trace length, spacing, dip angle, and aperture), the global connectivity of fracture networks is quantified by the entropy scale (Hs), while the directional entropy scale (Hs,α) is used to characterize the local geometrical anisotropy in arbitrary orientations. A series of hydraulic representative elementary volumes (REVs) of fracture patterns with various geometrical properties are acquired based on continuum analysis. The permeability in the continuum scale is obtained from steady-state flow simulations. Sensitivity analyses are performed to understand the geometrical dependence of permeability parameters regarding entropy indices. It is found that a systematic increase in trace length, spacing, and dip angle is correlated with an increase, decrease, and equilibrium in entropy, respectively, which corresponds to a change in hydraulic REV sizes that can be expressed as a power-law function related to the Hs. Moreover, Hs,α can well explain the permeability anisotropy resulting from the spatial order of fracture networks, and a unified mathematical relationship for the effective permeability coefficients in arbitrary orientations versus the Hs,α is proposed, independent of variations in fracture patterns and scales. The results indicate that geological entropy, related to the geometrical properties and spatial distribution of fractures, is appropriate to characterize the permeability of anisotropic systems.

A Connectivity Metrics-Based Approach for the Prediction of Stress-Dependent Fracture Permeability

Rapid and accurate assessment of fracture permeability is critical for subsurface resource and energy development as well as rock engineering stability. Fracture permeability deviates from the classical cubic law under the effect of roughness, geological stress, as well as mining-induced stress. Conventional laboratory tests and numerical simulations are commonly costly and time-consuming, whereas the use of a connectivity metric based on percolation theory can quickly predict fracture permeability, but with relatively low accuracy. For this reason, we selected two static connectivity metrics with the highest and lowest prediction accuracy in previous studies, respectively, and proposed to revise and use them for fracture permeability estimation, considering the effect of isolated large-aperture regions within the fractures under increasing normal stress. Several hundred fractures with different fractal dimensions and mismatch lengths were numerically generated and deformed, and their permeability was calculated by the local cubic law (LCL). Based on the dataset, the connectivity metrics were counted using the revised approach, and the results show that, regardless of the connectivity metrics, the new model greatly improves the accuracy of permeability prediction compared to the pre-improved model, by at least 8% for different cutoff aperture thresholds.

Investigation on damage-permeability model of dual-porosity coal under thermal-mechanical coupling effect

Understanding the permeability characteristics of coal under mining disturbance is crucial for ensuring coal mine safety and efficient gas extraction. Coal is a dual porosity medium consisting of matrix and fracture, and there are some differences in mechanics and permeability between matrix pores and fracture. However, research on the damage and gas seepage characteristics of dual-porosity coal is limited. In this paper, a coupled damage-permeability model considering matrix pores and fractures in coal is established, incorporating the influences of effective stress, gas adsorption, thermal expansion, and thermal cracking. And the reliability of the newly developed model was verified using experimental data of temperature and pressure variations under different stress boundary conditions. The results indicate that during the elastic stage, the total permeability and fracture permeability of coal exhibit a trend of decreasing and then increasing with pore pressure, while matrix permeability gradually increases. In the full stress-strain stage, the overall damage-permeability and fracture damage-permeability of coal exhibit an “S"-shaped variation trend with axial strain, while matrix damage-permeability shows a slow increasing trend. To accurately characterize the evolution of gas seepage in coal, contributions from matrix pores and fractures must be comprehensively considered, and the effects of gas adsorption, effective stress, thermal cracking, and thermal expansion on permeability cannot be ignored. Furthermore, through parameter sensitivity analysis, it is found that during the elastic stage, coal permeability decreases with an increase in the adsorption sensitivity coefficient and thermal expansion coefficient. In the full stress-strain process, coal permeability increases with an increase in the damage-permeability coefficient. The results of this study are of great significance for predicting the evolution of coal permeability in the working face ahead under mining disturbance.

An approach for assessment of CO2 leakage using mechanistic modelling: CO2 injection in deep saline aquifer of Lithuanian basin in presence of fault and fractures

Injecting CO2 into deep saline aquifers is a prominent strategy for carbon capture and storage (CCS) to mitigate greenhouse gas emissions. However, ensuring the long-term integrity of CO2 storage is crucial to prevent leakage and potential environmental hazards. This paper investigates the impact of presence of faults and fracture on CO2 leakage volumes. Particular case of CO2 injection into a deep saline aquifer for carbon capture and storage (CCS) applications is investigated. This paper explores the relationship between fracture permeability and the potential for CO2 leakage.

Optimization of Financial Indicators in Shale-Gas Wells Combining Numerical Decline Curve Analysis and Economic Data Analysis

We present a methodology to determine optimal financial parameters in shale-gas production, combining numerical simulation of decline curves and stochastic modeling of the gas price. The mathematical model of gas production considers free gas in the pore and the gas adsorbed in kerogen. The dependence of gas production on petrophysical parameters and stimulated permeability is quantified by solving the model equations in a 3D geometry representing a typical fractured shale well. We use Monte Carlo simulation to characterize the statistical properties of various common financial indicators of the investment in shale-gas. The analysis combines many realizations of the physical model, which explores the variability of porosity, induced permeability, and fracture geometry, with thousands of realizations of gas price trajectories. The evolution of gas prices is modeled using the bootstrapping statistical resampling technique to obtain a probability density function of the initial price, the drift, and the volatility of a geometric Brownian motion for the time evolution of gas price. We analyze the Net Present Value (NPV), Internal Rate of Return (IRR), and Discounted Payback Period (DPP) indicators. By computing the probability density function of each indicator, we characterize the statistical percentile of each value of the indicator. Alternatively, we can infer the value of the indicator for a given statistical percentile. By mapping these parametric combinations for different indicators, we can determine the parameters that maximize or minimize each of them. We show that, to achieve a profitable investment in shale-gas with high certainty, it is necessary to place the wells in extremely good locations in terms of geological parameters (porosity) and to have exceptional fracturing technology (geometry) and fracture permeability. These high demands in terms of petrophysical properties and hydrofracture engineering may explain the industry observation of “sweet spots”, that is, specific areas within shale-gas plays that tend to yield more profitable wells and where many operators concentrate their production. We shed light on the rational origin of this phenomenon: while shale formations are abundant, areas prone to having a multi-parameter combination that renders the well profitable are less common.