Changes In 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.

Unloading-induced permeability recovery in rock fractures

Underground space creation and energy extraction, which induce unloading on rock fractures, commonly occur in various rock engineering projects, and rock engineering projects are subjected to high temperatures with increasing depth. Fluid flow behavior of rock fractures is a critical issue in many subsurface rock engineering projects. Previous studies have extensively considered permeability evolution in rock fractures under loading phase, whereas changes in fracture permeability under unloading phase have not been fully understood. To examine the unloading-induced changes in fracture permeability under different temperatures, we performed water flow-through tests on fractured rock samples subjected to decreasing confining pressures and different temperatures. The experimental results show that the permeability of fracture increases with unloading of confining pressure but decreases with loading-unloading cycles. Temperature may affect fracture permeability when it is higher than a certain threshold. An empirical model of fracture hydraulic aperture including two material parameters of initial normal stiffness and maximum normal closure can well describe the permeability changes in rough rock fracture subjected to loading-unloading cycles and heating. A coupled thermo-mechanical model considering asperity damage is finally used to understand the influences of stress paths and temperatures on fracture permeability.

Multi-physics numerical analyses for predicting the alterations in permeability and reactive transport behavior within single rock fractures depending on temperature, stress, and fluid pH conditions

The aim of the current study was to establish a validated numerical model for addressing the changes in permeability and reactive transport behavior within rock fractures based on the fluid pH under coupled thermal-hydraulic-mechanical-chemical (THMC) conditions. Firstly, a multi-physics reactive transport model was proposed, considering the geochemical reactions that depend on the temperature, stress, and fluid chemistry conditions (e.g., fluid pH and solute concentrations), as well as the changes in permeability in the rock fractures driven by these reactions, after which the correctness of the model implementation was verified by solving the 1D reactive transport problem as a fundamental benchmark. Secondly, the validity of the model against actual rock fractures was investigated by utilizing the model to replicate the measurements of the evolving permeability and the effluent element concentrations in single granite fractures obtained by means of two flow-through experiments using deionized water (pH ∼ 6) and a NaOH aqueous solution (pH ∼ 11) as permeants under stressed, temperature-elevated conditions. The model predictions efficiently followed the changes in fracture permeability over time measured by both experiments. Additionally, the observed difference in the changing rates, which may contribute to the difference in the fluid pH between the two experiments, was also captured exactly by the predictions. Moreover, in terms of the effluent element concentrations, among all the elements targeted for measurement, the concentrations of most elements were replicated by the model within one order of discrepancy. Overall, it can be concluded that the developed model should be valid for estimating the changes in permeability and reactive transport behavior within rock fractures induced by geochemical reactions which depend on the fluid pH under coupled THMC conditions.

Influence of Fracture Types on Oil Production in Naturally Fractured Reservoirs

Since more than half of the crude oil is deposited in naturally fractured reservoirs, more research has been focused on characterizing and understanding the fracture impact on their production performance. Naturally open fractures are interpreted from Fullbore Formation Micro-Imaging (FMI) logs. According to the fracture aperture, they are classified as major, medium, minor and hairy fractures in decreasing order of their respective aperture size. Different fracture types were set up in this work as a Discrete Fracture Network (DFN) in synthetic models and a sector model from a highly naturally fractured carbonate reservoir. The field sector model includes four wells containing image logs from two wells and production data from two other wells. Numerous simulations were conducted to capture the contribution of fracture type on production performance. Primary recovery was used for synthetic and field sector models, while waterflooding and gas injection scenarios were considered just for the synthetic models. The results showed that the fracture type and its extent play an essential role in production for all studied models. The reservoir production capabilities might be underestimated by ignoring any fracture types present in the reservoir, especially the major ones. In the secondary recovery, fractures had different impacts. Better displacement and higher recovery were promoted for waterflooding, whereas faster breakthrough times were observed for the gas injection. The performance during gas injection was more dependent on fracture permeability changes than waterflooding. This study’s findings can help in better understanding the impact of the different types of fracture networks on oil recovery at the various production stages. Additionally, the history matching process can be improved by including all types of fractures in the dynamic model. Any simplification of the fracture types might end in overestimating or underestimating the oil recovery.

A permeability model for coal based on elastic and plastic deformation conditions under the interaction of hydro-mechanical effects

In engineering activities involving the mining of coal resources, gas is the main factor for causing coal and gas explosions accidents, with permeability being an important parameter in estimating gas emissions. With the steady development of the mining face, stress in front of the work face has evidently changed, that has resulted in coal damage under mining disturbance. In the underground environment, coal is in a complex environment where water, gas and external loads combine with each other, leading to changes in permeability that are often extremely complex, with effective stress being the dominant factor to changes in permeability. Therefore, coal permeability change related to damage-induced effects under different water contents should be further studied. In this study, first, the influence of water, gas adsorption and effective stress on coal fracture permeability change were considered. Further, damage variables were introduced to combine mechanical damage with water weakening damage. By quantifying changes in matrix sizes with new fracture generations, the plastic deformation in fractures was estimated. Based on a cubic model, a damaged-induced permeability model under the interaction of hydro-mechanical effects was established. From this, a triaxial seepage experiment involving the whole stress-strain process, including effective stress changes of water-bearing coal, was conducted to compare with, and to verify the results against an established model. The experimental results revealed that changes in axial strain and permeability was “S” shaped during the whole stress-strain process. In addition, during the whole stress-strain and effective stress changes process, the permeability model corresponded well with the experimental results. This demonstrated that the model could not only predict permeability change under elastic deformation, but could also describe permeability changes under plastic deformation during the damage stage. The purpose of this study was to provide a new method for predicting the permeability evolution law relating to coal mining and gas extraction.

Scale-independent relationship between permeability and resistivity in mated fractures with natural rough surfaces

Geothermal systems consisting of fractures in impermeable rocks are difficult to characterize by in situ methods. In an effort to link characteristics of small-scale and large-scale fractures, this study investigated possible relations between their geophysical parameters. We upscaled the relationship between fracture permeability and formation factor in a laboratory specimen to larger fracture dimensions. Microscopic flow characteristics indicate that this relationship is related to the tortuosity of flow paths. We derived an empirical formula that directly predicts changes in fracture permeability from changes in formation factor. This relation may make it possible to monitor subsurface hydraulic activities through resistivity observations.

Evolution of Fracture Aperture in Quartz Sandstone under Hydrothermal Conditions: Mechanical and Chemical Effects

Fractures efficiently affect fluid flow in geological formations, and thereby determine mass and energy transport in reservoirs, which are not least exploited for economic resources. In this context, their response to mechanical and thermal changes, as well as fluid–rock interactions, is of paramount importance. In this study, a two-stage flow-through experiment was conducted on a pure quartz sandstone core of low matrix permeability, containing one single macroscopic tensile fracture. In the first short-term stage, the effects of mechanical and hydraulic aperture on pressure and temperature cycles were investigated. The purpose of the subsequent intermittent-flow long-term (140 days) stage was to constrain the evolution of the geometrical and hydraulic fracture properties resulting from pressure solution. Deionized water was used as the pore fluid, and permeability, as well as the effluent Si concentrations, were systematically measured. Overall, hydraulic aperture was shown to be significantly less affected by pressure, temperature and time, in comparison to mechanical aperture. During the long-term part of the experiment at 140 °C, the effluent Si concentrations likely reached a chemical equilibrium state within less than 8 days of stagnant flow, and exceeded the corresponding hydrostatic quartz solubility at this temperature. This implies that the pressure solution was active at the contacting fracture asperities, both at 140 °C and after cooling to 33 °C. The higher temperature yielded a higher dissolution rate and, consequently, a faster attainment of chemical equilibrium within the contact fluid. X-ray µCT observations evidenced a noticeable increase in fracture contact area ratio, which, in combination with theoretical considerations, implies a significant decrease in mechanical aperture. In contrast, the sample permeability, and thus the hydraulic fracture aperture, virtually did not vary. In conclusion, pressure solution-induced fracture aperture changes are affected by the degree of time-dependent variations in pore fluid composition. In contrast to the present case of a quasi-closed system with mostly stagnant flow, in an open system with continuous once-through fluid flow, the activity of the pressure solution may be amplified due to the persistent fluid-chemical nonequilibrium state, thus possibly enhancing aperture and fracture permeability changes.

Thermal effect on permeability in a single granite fracture: Experiment and theoretical model

The behavior of fluid flow through rock fractures at varying temperatures is a critical issue in many subsurface geo-energy projects. Previous work has considered the thermal effects on fracture permeability, but not in isolation of the chemical effects as well. Therefore, to quantitatively assess the mechanical influences on fracture permeability, we present results from permeability tests of five cylindrical Beishan granite samples, each with a single artificial fracture, at different temperatures. Three samples were tested at a constant confining pressure of 5 MPa and temperatures of 22 °C, 90 °C and 150 °C for 22 days, to examine creep-induced changes in fracture permeability. Fracture permeability decreases with time until about 10 days, and the eventual magnitudes of fracture permeability reduction are much greater at 90 °C and 150 °C than at 22 °C. Two samples were subjected to three heating cycles (30 °C to 150 °C) at a constant confining pressure of 5 MPa. Fracture permeability decreases as temperatures increase from 30 °C to 150 °C, and then slight changes in permeability occur as the sample is cooled to 30 °C. A similar tendency appears in subsequent temperature cycles, while the magnitude of fracture permeability reduction decreases with increasing heating-cooling cycles. A coupled thermal-mechanical model considering asperity damage is developed to describe the thermally-induced changes in fracture permeability, which properly predicts the experimental results. The residual deformation of asperities and temperature dependent Young's modulus play an important role in thermally-induced changes in fracture permeability.

Mechanical-Chemical-Mineralogical Controls on Permeability Evolution of Shale Fractures

We report experimental observations of permeation of CO2-rich aqueous fluids of varied acidic potential (pH) on three different shales to investigate mechanical, chemical, and mineralogical effects on fracture permeability evolution. Surface profilometry and SEM-EDS (scanning electron microscopy with energy-dispersive X-ray spectroscopy) methods are employed to quantify the evolution in both roughness on and chemical constituents within the fracture surface. Results indicate that, after 12 hours of fluid flow, fracture effective hydraulic apertures evolve distinctly under different combinations of shale mineralogy, effective stress, and fluid acidity. The evolution of roughness and transformation of chemical elements on the fracture surface are in accordance with the evolution of permeability. The experimental observations imply that (1) CO2-rich aqueous fluids have significant impact on the evolution of fracture permeability and may influence (and increase) shale gas production; (2) shale mineralogy, especially calcite mineral, decides the chemical reaction and permeability increasing when CO2-rich aqueous fluids flow through fractures by free-face dissolution effect; (3) clay mineral swelling reduces fracture aperture and additively calcite pressure solution removes the bridging asperities, which are the main reasons for fracture permeability decrease; (4) competition roles among clay mineral swelling, mineral pressure solution, and free-face dissolution determine how fracture permeability changes. Furthermore, a multiple parameter model is built to analyze effective hydraulic aperture evolution in considering above three mechanisms, which provide a reference to forecast fracture permeability evolution in shale formations.

Modeling of coupled thermal-hydraulic-mechanical-chemical processes for predicting the evolution in permeability and reactive transport behavior within single rock fractures

A multi-physics numerical model was developed to predict the fluid flow and mass transport behavior of rock fractures under coupled thermal-hydraulic-mechanical-chemical (THMC) conditions. In particular, the model was employed for the purpose of describing the evolution of permeability and reactive transport behavior within rock fractures by taking into account the geochemical processes of the free-face dissolution and the pressure dissolution. In order to examine the capability of the developed model, the model was applied to replicate the experimental measurements of the evolution in hydraulic aperture, permeability, and element concentrations obtained from two flow-through experiments using single granite and mudstone fractures. The model predictions for the granite experiment were able to follow the actual data for the evolution in hydraulic aperture and effluent element concentrations without adopting any fitting parameters that are often used in other THMC coupled models obtained from literature. Furthermore, the model succeeded in replicating the actual changes in fracture permeability and effluent element concentrations within the mudstone fracture. Although some uncertain mismatches between the experiments and the model predictions, such as changes in the concentrations of several elements (i.e., Na and K concentrations in the granite fracture and Al in the mudstone fracture) were remaining at this stage, the developed model should be valid for evaluating the evolution in the fluid flow and mass transport behavior within rock fractures induced by mineral dissolution under stress- and temperature-controlled conditions.

A new model for calculating permeability of natural fractures in dual-porosity reservoir

During the development of naturally fractured carbonate reservoirs, understanding the change in fracture permeability is the basis for production evaluation and scientific development. The conventional method of analyzing fracture permeability is to take core samples for laboratory experiments. This paper presents a new method to calculate the fracture permeability decrease using actual reservoir pressure data. The mathematical model of fracture permeability change with pressure is established based on material balance in the production process of a fractured reservoir. The model considers crossflow coefficient as well as compression coefficient. According to the results of the model, the fracture permeability decreases with decrease of the formation pressure, but the degree of decline is related to the crossflow coefficient and the compression coefficient. By using this model, the change in fracture permeability can be calculated under different production pressures. This provides a new method for stress sensitivity determination of fractured reservoirs. Cited as : Zhang, T., Li, Z., Adenutsi, C.D., et al. A new model for calculating permeability of natural fractures in dual-porosity reservoir. Advances in Geo-Energy Research, 2017, 1(2): 86-92, doi: 10.26804/ager.2017.02.03

The effects of nearby fractures on hydraulically induced fracture propagation and permeability changes

Fracture propagation caused by hydraulic fracturing operations can be significantly influenced by adjacent fractures. This paper presents a detailed coupled hydro-mechanical analysis to study the effects of nearby natural fractures on hydraulically induced fracture propagation and changes in fracture permeability. Two rock domains were considered in comparison: FD1, with one fracture, and FD2, with two adjacent parallel or non-parallel fractures. It was assumed that water injection occurred in a borehole that intersected the single fracture in FD1 and one of the two fractures in FD2. Simulations were made for a time period of 3h with an injection period of 2h followed by 1h of shut-in. An elastic-brittle model based on the degradation of material properties was implemented in a 2D finite-difference scheme and used for elements of the intact rock subjected to tension and shear failure. The intact rock was considered to have a low but non-negligible permeability. A verification study against analytical solutions showed that the fracture propagation and stress concentrations due to differential boundary stresses could be accurately represented by our model. Next, a base case was considered, in which the stress ratio (SR) between the magnitudes of the maximum and minimum boundary stresses, the permeability kR of the intact rock and the initial permeability kTF of the tension failure regions were fixed. In FD2, the distance dF between the two natural fractures defined by the closest distance was also fixed. The results showed that in both rock domains, the fracture started to propagate when the pore pressure was approximately 85% of the magnitude of the minimum boundary stress. The propagation of a single fracture was significantly greater than the propagation of a double fracture system because, in the latter case, the pore pressure decreased when the two fractures connected. As a result, changes in permeability in FD2 were smaller than in FD1. At the end of injection, the maximum ratios between the final and initial permeability of the natural fractures were found to be approximately 3 and 2 for rock domains FD1 and FD2, respectively. For non-parallel fractures, the controlling factor for fracture propagation was the separation between the tips of the pressurised fracture and the neighbouring non-pressurised fracture. A sensitivity study was conducted to study the influence of the key parameters dF, SR, kR and kTF on the simulation results. Fracture propagation showed more sensitivity to dF and SR than to the other parameters.

The role of mineral heterogeneity on the hydrogeochemical response of two fractured reservoir rocks in contact with dissolved CO2

In this study, we compare the hydrogeochemical response of two fractured reservoir rocks (limestone composed of 100 wt.% calcite and clast-poor sandstone composed of 66 wt.% calcite, 28 wt.% quartz and 6 wt.% microcline) in contact with CO2-rich sulfate solutions. Flow-through percolation experiments were performed using artificially fractured limestone and sandstone cores and injecting a CO2-rich sulfate solution under a constant volumetric flow rate (from 0.2 to 60 mL/h) at P = 150 bar and T = 60 °C. Measurements of the pressure difference between the inlet and the outlet of the samples and of the aqueous chemistry enabled the determination of fracture permeability changes and net reaction rates. Additionally, X-ray computed microtomography (XCMT) was used to characterize and localize changes in the fracture volume induced by dissolution and precipitation reactions.In all reacted cores, an increase in fracture permeability and in fracture volume was always produced even when gypsum precipitation happened. The presence of inert silicate grains in sandstone samples favored the occurrence of largely distributed dissolution structures in contrast to localized dissolution in limestone samples. This phenomenon promoted greater dissolution and smaller precipitation in sandstone than in limestone experiments. As a result, in clast-poor sandstone reservoirs, the larger increase in fracture volume, as well as the more extended distribution of the created volume, would favor the CO2 storage capacity. The different distribution of created volume between the limestone and sandstone experiments led to a different variation in fracture permeability. The progressive stepped permeability increase for sandstone would be preferred to the sharp permeability increase for limestone to minimize risks related to CO2 injection, favor capillary trapping and reduce energetic storage costs.2D reactive transport simulations that reproduce the variation in aqueous chemistry and the fracture geometry (dissolution pattern) were performed using CrunchFlow. Given that calcite dissolution reaction at pH < 5 is transport controlled, the calcite reactive surface area used in the model had to be diminished with respect to the geometric surface area initially considered in order to fit the model to the experimental data. The fitted reactive surface area was higher under faster flow conditions, reflecting a decrease in transport control and a more distributed reaction in sandstone compared to limestone.

Fully coupled analysis of interaction between the borehole and pre-existing fractures

The coupling of rock and thermal stresses along with fluid pressure are particularly important in fractured rock masses, since stress-induced changes in permeability can be large and irreversible under perturbations resulting from various natural and induced activities. A new method is presented to model fracture permeability changes during drilling in fractured rocks. The approach includes finite element method (FEM) for fully coupled thermo-poroelastic analysis of stress distribution around borehole and displacement discontinuity method (DDM) to model fracture deformation. Three cases of overbalanced, underbalanced, and balanced drilling fluid pressure conditions are employed. The application of the approach illustrates that the maximum variation of aperture occurs near to the borehole and become negligible at large distances away from the borehole. It was shown that mechanical stresses caused by excavation of the rock contribute to short time while fluid pressure and thermal stresses are responsible for long term permeability variation of fractures. The results show that the fracture permeability decreases with depletion of the fracture and the rock matrix while increases with pressurization and cooling of fracture during overbalanced condition. The fracture permeability reduces during balanced fluid pressure condition within a short time then enhances by cooling of the rock surrounding the borehole.

Linking microearthquakes to fracture permeability change: The role of surface roughness

AbstractDespite its importance, the relation between microearthquakes (MEQs) and changes in hydraulic properties during hydraulic stimulation of a fractured reservoir has rarely been explored, and it is still not well understood. To investigate this relation, we first formulate a plausible scale dependence, where fracture length and shear displacement are variables, for channeling flow through heterogeneous aperture distributions for joints and faults. By combining this formulation with the concept of the seismic moment, we derive quantitative relations between the moment magnitude (Mw) of MEQs and the fracture permeability change in the directions orthogonal to (kfault,⊥/kjoint) and parallel to (kfault,∥/kjoint) the shear displacement, in the form and . Despite the simplicity of the derivation, these relations have the potential to explain the results of field experiments on hydraulic stimulation, such as the enhanced geothermal systems at Soultz‐sous‐Fôret and Basel.

Coupled thermo-poroelastic analysis of drilling induced mechanical damage in fractured rocks

The wellbore represents one of the most crucial components in the hydrocarbon and geothermal reservoir system, as it is the sole conduit to the reservoir for fluid production or injection. Therefore, predicting and controlling of the permeability variations close to the wellbore has been one of the most challenging issues in geothermal and petroleum reservoir systems. A new method is presented to model fracture permeability changes during drilling in fractured rocks. The approach includes finite element method (FEM) for fully coupled thermo-poroelastic analysis of stress distribution around borehole and displacement discontinuity method (DDM) to model fracture deformation. Four models of fracture networks with different facture spacing and varied inclination angle are considered. Permeability variations in underbalanced and overbalanced drilling operations are compared together in different models. The results indicate the difference in effective stress values along x and y directions exceed over 40MPa around borehole and along fracture surface. It was proved that the mechanical stresses caused by excavation of the rock contribute to short time while fluid pressure and thermal stresses contribute to long term permeability change of fractures. The application of the approach illustrates that the maximum variation of fracture aperture occurs near to the borehole and becomes negligible at large distance away from the borehole. Regardless of the drilling operation method, either overbalanced or underbalanced conditions, the permeability of fractures intersecting borehole decreases for large time after drilling. The maximum variations in fracture permeability occur in fracture network with inclination angle of 45 degrees where maximum variation of effective normal and shear stresses occur. Also, initial poroelastic effect of stresses and fluid pressure on the permeability is maximized by increasing fracture spacing.

A new correlation to evaluate the fracture permeability changes as reservoir is depleted

The increasing development of unconventional resources plays an important role in filling the gap between demand and conventional oil and gas supply. Due to the nature of low permeability, tight gas and shale reservoirs need fractures, natural and artificial, to produce hydrocarbon at commercial rates. Fracture permeability is a key factor affecting the development of these unconventional reservoirs. It is observed that fracture permeabilities decline as reservoirs are depleted because pore pressure declines lead to the closures of fractures and the permeability reductions. Therefore a correlation to quantify the variations of the fracture permeability with pore pressure is highly needed. In this study we investigate the effects of pore pressures on fracture permeabilities assuming constant in-situ stresses exert on the formations. Starting from the force balance, we derived equations to calculate fracture permeability based on fracture geometry. Our new correlations can also be used to evaluate the changing fracture permeability during the recovery of hydrocarbon. The proposed correlations provide a way to estimate the fracture permeability at initial pressure and the depleted pressure at any production stage. Although some experiments had been conducted to build relationships between fracture permeability and pressure for some types of rocks. It is noted that experiments are time consuming and cost expensive. Sometimes, the unavailability of shale sample and difficulty in preparing shale core plug also limit the number of experiment. Our research provided a theoretical model. We realize that theoretical results are not necessarily the ground truth because of the many implicit and explicit assumptions made to obtain an analytical formula. Therefore, extensive sensitivity study was conducted to quantify the effects of important parameters on permeability change. The proposed methods considered the laminar flow as well as turbulent flow in the fracture, which is often observed in gas well. Under the conditions of no core sample available to test the impact of pressure on fracture permeability, or special core analyses prohibited by cost and time, the proposed correlations are powerful tools to estimate the change of permeability with producing time.

Numerical Simulation of Fracture Permeability Change in Production of Pressure-sensitive Reservoirs with In-situ Stress Field

In pressure sensitive reservoirs, interaction effects among the porous media flow field, the fracture field and the stress field can cause some specific flow characteristics entirely different from those in conventional reservoirs. Dynamic fracture behavior is one of them, which generates a change in the value of fracture aperture and even a variation in the anisotropy of permeability. In this paper, we focus on the dynamic behavior of fractures and some affecting factors, including driving pressure and in-situ stress. Numerical discrete fracture network (DFN) models are built and solved by the finite element method to investigate what the range-ability the fracture presents and what impact these affecting factors have. In these mathematical models, both dynamic fractures and the fluid-solid coupling are taken into account, and a stress-strain model, a flow field model and a fluid-solid coupling model are included. Based on the models, the variation of fracture aperture in pressure sensitive reservoirs is studied and the results show that a different direction and connectivity of fractures lead fracture dilation to varying degrees as pressure changes so that the idea of anisotropic fracture porosity is proposed for reservoir scale simulation. The study also indicates that the drop of formation pressure determines the conductivity of fractures and anisotropy of permeability but just has a slight impact on the direction of principal permeability. Finally, the study shows the interaction of the in-situ stress pressure and the fracture field.

A poroelastic model for evolution of fractured reservoirs during gas production

Coupled processes between matrix deformation and fluid flow in fractured reservoirs such as gas shale are important for predicting fracture permeability change and reservoir production behavior. In contrast to sandstone reservoirs, the coupling between gas desorption and rock matrix/fracture deformation must be accounted for in poroelastic response of gas shale. For this purpose, a constitutive relation is developed and used in this work. The continuity equation of dry gas considers the mass conservation including both free and absorbed phases. The absorbed gas content and the sorption-induced volumetric strain are described through a Langmiur-type equation. A porosity model is developed and utilized in the governing equations, and a discrete system of fractures is included in flow and rock deformation analysis. The resulting field equations are solved using a finite element model based on the dual permeability method (DPM). The model is then used to investigate coupled desorption/diffusion-rock deformation phenomena including fracture deformation (both normal and shear deformation with dilation), and its impact on gas flow in naturally fractured reservoir. Simulation results show that the time evolution of gas pressure, effective stresses, fracture aperture, and permeability are strongly affected by gas desorption during production, especially in the near-wellbore region. Gas desorption retards the influence of the effective stress increase associated with pore pressure reduction during production. The combination of in-situ stress condition and gas desorption mechanism governs the fracture deformation behavior in fractured gas shale reservoirs.

Permeability changes in simulated granite faults during and after frictional sliding

Thermal–hydrological–mechanical coupling processes suggest that fault permeability should undergo dynamic change as a result of seismic slip. In igneous rocks, a fault's slip surface may have much higher permeability than the surrounding rock matrix and therefore operate as a conduit for fluids. We conducted laboratory experiments to investigate changes in fracture permeability (or transmissivity) of a fault in granite due to shear slip and cyclic heating and cooling. Our experiments showed that high initial fracture transmissivity (>10−18 m3) was associated with a high friction coefficient and that transmissivity decreased during slip. We propose that this reduction in transmissivity reflects the presence of gouge in fracture voids, increasing the area of contact in the fault plane and reducing the hydraulic aperture. In contrast, when initial fracture transmissivity was low (<10−18 m3), we observed that friction was lower and transmissivity increased during slip. The high transmissivity and high friction may be explained by large areas of bare rock being in contact on the slip surface. Slip velocity had little influence on the evolution of permeability, probably because gouge produced at different slip velocities had similar grain size distributions, or because gouge leaked from the slip surface. Transmissivity decreased with increasing temperature in heating tests, probably due to thermal expansion increasing normal stress on the fracture. Frictional heating did not influence transmissivity during the shearing tests.