Stress Dependence Of Permeability Research Articles

Anisotropic flow characteristics in single-fractured tensile and shear fractures in granite subjected to various confining stress

Anisotropic flow characteristics in single-fractured tensile and shear fractures in granite subjected to various confining stresses were investigated by experiments and experimental results-based flow simulations. Anisotropic characteristics in aspects such as the permeability reduction rate, stress dependency of permeability, and flow paths in fracture and fracture aperture distribution were analysed and compared between tensile and shear fractures. The main conclusions are as follows: (1) for tensile fractures, the permeability in the X direction, k X , is slightly lower than the permeability in the Y direction, k Y , and the average permeability anisotropic coefficient, α k ( α k = k X / k Y ), is in the range 0.236–0.779. For shear fractures, k X is obviously lower than k Y , and α k is in the range 0.038–0.163; therefore, the permeability anisotropy in shear fractures is stronger than in tensile fractures. (2) Strong channelling effects exist in both shear and tensile fractures. The stress-dependence coefficient of permeability is 0.731 MPa −1 in the X direction and 0.365 MPa −1 in the Y direction for tensile fractures, and 0.034 and 0.010 MPa −1 , respectively, for shear fractures, indicating that the dependency of permeability on stress also shows anisotropy. (3) An empirical model for α k based on stress and fracture aperture variograms is proposed. Based on α k , permeability along both the X and Y directions can be well predicted, especially under relatively high confining stress.

Stress-dependence of the permeability, porosity, and compressibility in fractured porous media regarding fracturing condition

Fractured reservoirs are important hydrocarbon resources. However, the production of hydrocarbon makes fractures to be sealed which in turn decreases the production rate. A better understanding of permeability, porosity, and compressibility of fractures would be useful in optimizing the production rate. This research paper explored stress-dependent permeability, porosity, and compressibility of fractured porous media, both experimentally and numerically. The laboratory results are used to calibrate numerical models. With this regard, the roles of fracturing parameters such as orientation, opening, fracture density, persistency, and the intersection of fractures on hydro-mechanical parameters of the fractured sample are analyzed individually. The results indicate that stress sensitivity of permeability and compressibility is more in fractured porous media than in non-fractured ones. The results gained also showed that samples with open fractures and no filling materials, dominant vertical fractures, and high fracture density have the most stress dependency of permeability and compressibility, while in high fracture densities, the fracture and matrix changes are close to each other. The intersection of joints and not persisted fractures act as obstacles. This causes the fluid to be trapped in porous media that affect reservoir recovery and increase financial losses. Finally, an analytical relationship is developed to calculate the matrix compressibility

The optimum pressure drawdown for production from a shale gas reservoir: A numerical study with a coupled geomechanics and reservoir model

Pressure drawdown in a production well is a key parameter to control and optimize hydrocarbon production from the reservoirs. During production process in a stress-sensitive unconventional reservoir, there exist two competing mechanisms that are related to the pressure drawdown and impact the production: pressure gradient between the reservoir and production well and stress dependency of permeability. The combination of the two mechanisms results in the potential existence of the optimum pressure drawdown beyond which the production rate decreases with further increasing pressure drawdown for a given reservoir. This study investigates the factors impacting the optimum drawdown based on a coupled geomechanics and reservoir model. Specifically, we employed a reservoir simulator (TOUGH2) coupled with a geomechanics simulator (FLAC3D) to model the reservoir gas production under stress effects on porosity and permeability. The reservoir matrix permeability is exponentially related to the change in effective stress through the stress sensitivity factor. Simulation results show that the optimum pressure drawdown exists only for stress-sensitive shale reservoirs and mainly depends on the stress sensitivity factor, rather than the initial reservoir matrix permeability. This provides a simple guideline for the pressure drawdown management; the pressure drawdown should not exceed the optimum pressure drawdown in the field operations.

Stress dependency of permeability, porosity and flow channels in anhydrite and carbonate rocks

This study investigates the effect of stress magnitude and stress history on porosity and permeability values of anhydride and carbonate rocks. Porosity and permeability properties are measured for twelve anhydride and carbonate core samples under stress loading and unloading conditions. The results of permeability measurements show that tighter core samples are more stress dependent while the anhydride samples are generally more sensitive to the stress. The gap between stress loading and unloading (hysteresis) is more considerable at lower effective stress values. The results also indicate that the hysteresis is more noticeable in the anhydride core samples. The gas slippage factor is also determined which specifies the flow channels systems of rocks. Three different flow channels systems are observed in the anhydride core samples while the carbonate core samples show one flow channels system. Porosity measurements show that, it has less sensitivity to the stress for both anhydride and carbonate core samples.

Permeability and physical properties of semi-compacted fine-grained sediments – A laboratory study to constrain mudstone compaction trends

Permeability and physical properties of fine-grained clastic sediments show a wide range of variations. Despite rather intensive research, the impact of grain size distribution and mineralogical composition of individual rock constituents is not thoroughly investigated. We performed mechanical compaction of brine-statured reconstituted borehole cuttings and synthetic quartz-clay mixtures to study the evolution of properties in fine-grained clastic sediments during burial. The primary objective was to examine whether the hydraulic and physical properties of fine-grained sediments could be described and constrained by binary quartz-clay mixtures. The synthetic binary mixtures were prepared by mixing quartz with non-swelling (kaolinite) and strongly-swelling (smectite) clays, which can represent the endmember properties within the clay minerals. In addition to vertical permeability, physical and seismic properties, stress-dependence of permeability, and two-phase relative permeability of brine-oil system were investigated. Experimental results show that grain size distribution and mineralogical composition control the vertical permeability. A well-constrained porosity-permeability bound is defined, where the compaction trends of pure quartz and quartz-smectite 15:85 (wt %) mixtures describe the maximum and minimum boundaries, respectively. The quartz-clay mixtures, however, fail to provide bounds to constrain the broad range of variations in physical and seismic properties of reconstituted aggregates, and consequently natural mudstones. It is crucial to incorporate microstructure into the permeability prediction models because the experiments indicated that the microscale characteristics control the macroscale fluid flow properties.

Stress-Dependent In Situ Gas Permeability in the Eagle Ford Shale

We measured argon gas permeability in three intact and one partially fractured Eagle Ford Shale samples documenting the stress dependence of horizontal (bedding parallel) in situ permeability of intact samples which varies between 1 and 10 nD (1 nD = 0.9869233 × 10−21 m2), while the permeability of partially fractured sample varies between 18 and 37 nD. For all samples, permeability decreases by up to an order of magnitude while cycling the confining pressure (PC) between 27.7 and 55.2 MPa at a constant pore pressure (PP) of 14.4 MPa. Most of the permeability decrease is within the first loading and unloading cycle. During this first cycle, we also observe less than 2% decline in permeability over ~ 10 days when we held the PC constant at 51.6–55.2 MPa, respectively. This suggests that the ongoing creep plays a relatively minor role. The subsequent PC cycles result in a small decrease in permeability (~ 6 to 26% variation between the start and the end of each cycle). We interpret that the initial permeability loss is due to the closing of micro-fractures—which we infer are caused by stress relief and gas expansion during sample retrieval and/or preparation. We interpret that the higher permeability of the partially fractured sample is mainly due to incomplete closure of a preexisting fracture, which extends nearly two-third the sample length. We document this dual-permeability structure from the observation of a dual-timescale pressure response behavior during the experiments at lower PC–PP. We find permeability decreases with increasing PC–PP; stress dependency of permeability follows an exponential relationship with a stress-sensitive gradient of 0.019–0.040 MPa−1. A better understanding of permeability variation with stress will help to reliably estimate in situ permeability and to better understand production evolution from unconventional shale reservoirs.

Permeability of Organic-Rich Shale

Summary Measured permeability of an organic-rich shale sample varies significantly with applied laboratory conditions, such as the confining pressure, temperature, and the measurement fluid type. This indicates that the measured quantity is influenced by several mechanisms that add complexity to the measurement. The complexity is mainly caused by stress dependence of the matrix permeability. Also, it is because organic-rich shale holds significant volumes of fluids in sorbed (adsorbed, dissolved) states; sorption can also influence the permeability through its own storage and transport mechanisms. The stress-dependence and sorption effects on permeability could develop under the reservoir conditions and influence the production, although we currently do not have a predictive permeability model that considers their coexistence. In this work, this is accomplished by considering that the shale matrix consists of multiple continua with organic and inorganic pores. Stress dependency of the permeability comes along with slit-shaped pores, whereas the sorption effects are associated with nanoscale organic capillaries. A simple conceptual flow model with an apparent shale permeability is developed that couples the molecular-transport effects of the sorbed phase with the stress dependence of the slit-shaped pores. The simulation results show the impact of the permeability model on the production. Sensitivity analysis on the new permeability model shows that the stress dependence of the overall transport is significant at high pore pressure, when the effective stress is relatively low. Diffusive molecular transport of the sorbed phase becomes important as the stress gets larger and, hence, the slit-shaped pores close. The constructed apparent-permeability vs. pore-pressure curves show the dominance of the molecular transport as an increase in permeability characterized by appearance of a minimum permeability value at the intermediate values of the pressure. One can use the new permeability model easily in history matching a well performance and optimizing its production.

Erratum to: Anisotropy and Stress Dependence of Permeability in the Barnett Shale

Erratum to: Anisotropy and Stress Dependence of Permeability in the Barnett Shale

Permeability dependency on stiff and compliant porosities: a model and some experimental examples

The relation between porosity and permeability is not unique. We show that stress dependencies of both porosity and permeability can provide useful information clarifying this relation. We propose that comparison of the functional dependency of porosity and permeability on stress shows which part of the void space in rocks controls the permeability, the compliant porosity or the stiff porosity. The compliant porosity (including very thin cracks and grain-contact vicinities) usually controls the stress dependencies of elastic moduli of rocks. One then observes exponential-like dependencies of elastic properties on effective stress. Stress-induced deformation of stiff pores (equant pores) have less significance for stress dependencies of elastic properties on loadings of low to moderate magnitudes (several tens of MPa). However, such pores can play a significant role in the stress dependency of permeability. We propose a rather general model of permeability as a function of the stiff and compliant porosity. The model includes the possibility that, in different rocks, permeability can be controlled by stiff pores or, alternatively, by compliant pores, or, finally, by a combination of these. This model predicts a functional dependency of permeability on stress, ranging from power-law to exponential-law and to a mixed behavior of permeability in these situations, respectively. We show experimental results for four samples of sedimentary rocks from oil reservoirs of the Russian Perm region indicating these types of behavior.

Anisotropy and Stress Dependence of Permeability in the Barnett Shale

We document vertical permeability of $$2.3 \times 10^{-21}\, \hbox {m}^{2}$$ (2.3 nd) and horizontal permeability of $$9.5 \times 10^{-20}\, \hbox {m}^{2}$$ (96.3 nd) in two Barnett Shale samples. The samples are composed predominantly of quartz, calcite, and clay; have a porosity and a total organic content of $$\sim $$ 4 % each; and have a thermal maturity of 1.9 % vitrinite reflectance. Both samples exhibit stress-dependent permeability when the confining pressure is increased from 10.3 to 41.4 MPa. We measure a permeability anisotropy, the ratio of the horizontal to the vertical permeability, of $$\sim $$ 40. We find that the permeability anisotropy does not vary with effective stress. Multiscale permeability, as demonstrated by pressure dissipation, is related to millimeter-scale stratigraphic variation. We attribute the permeability anisotropy to preferential flow along more permeable layers and attribute the stress dependence to pore closure. A determination of permeability anisotropy allows us to understand flow properties in horizontal and vertical directions and assists our understanding of upscaling. Characterization of stress dependency allows us to predict permeability evolution during production.

Experimental study of fluid transport processes in the matrix system of the European organic-rich shales: I. Scandinavian Alum Shale

This contribution presents results from a laboratory study investigating the fluid (gas/water) transport properties in the matrix system of the Scandinavian Alum Shale. The maturity of the organic matter of the shale samples ranged between 0.5 and 2.4% vitrinite reflectance (VRr). Gas (He, Ar, CH4) and water flow properties were determined at effective stresses ranging between 5 and 30 MPa and a temperature of 45 °C. The effects of different controlling factors/parameters on the fluid conductivity including permeating fluid, moisture content, anisotropy, heterogeneity, effective stress, pore pressure, and load cycling were analyzed and discussed. Pore volume measurements by helium expansion were conducted under controlled “in situ” effective stress conditions on a limited number of plugs drilled parallel and perpendicular to bedding.For Alum Shale the intrinsic permeability coefficients measured parallel and perpendicular to bedding (6·10−22–8·10−18 m2) were within the range previously reported for other shales and mudstones. Permeability coefficients were strongly dependent on permeating fluid, moisture content, anisotropy, effective stress and other sample-to-sample variations. The intrinsic/absolute permeabilities measured with helium were consistently, higher (up to five times) than those measured with argon and methane. Permeability coefficients (He, CH4) measured on a dry sample were up to six times higher than those measured on an “as-received” sample, depending on effective stress. The effect of moisture on measured permeability coefficients became more significant as effective stress increased. Permeability coefficients (He, CH4) measured parallel to bedding were up to more than one order of magnitude higher than those measured perpendicular to bedding. Parallel to bedding, all samples showed a nonlinear reduction in permeability with increasing effective stress (5–30 MPa). The stress dependence of permeability could be well described by an exponential relationship.

Experimental study of fluid transport processes in the matrix system of the European organic-rich shales: II. Posidonia Shale (Lower Toarcian, northern Germany)

A laboratory study has been conducted to investigate the transport of gases (He, Ar, CH4) and water in the matrix of Lower Toarcian Posidonia Shale samples from three shallow boreholes in northern Germany. The maturity of the organic matter of the shale samples ranged between 0.53 and 1.45% vitrinite reflectance (VRr). The measurements were performed at effective stresses ranging between 6 and 37MPa and a temperature of 45°C. The effects of different controlling factors including permeating fluid, maturity, anisotropy, moisture content and effective stress on the fluid conductivity were analyzed and discussed.Permeability coefficients measured perpendicular and parallel to bedding (3·10−22 to 9.7·10−17m2) were within the range previously reported for other shales and mudstones. They exhibited a strong dependence on permeating fluid, maturity, anisotropy, moisture content and effective stress. The permeability coefficients measured with helium as permeate were consistently higher (up to two times) than those measured with argon and methane. Permeability coefficients measured with water were up to three orders of magnitude lower than Klinkenberg-corrected gas permeability coefficients measured with helium and methane under similar experimental conditions. Among the samples studied, the lowest porosity and permeability coefficients were measured on samples of intermediate thermal maturity (0.88% VRr, oil-window). Permeability coefficients (He, CH4) measured parallel to bedding were up to more than one order of magnitude higher than those measured perpendicular to bedding. Permeability coefficients measured with He and CH4 on a dry sample were up to two times higher than those measured on a sample with the “as-received” moisture content. All samples showed a nonlinear reduction in permeability parallel to bedding with increasing effective stress (6–37MPa). The permeability anisotropy and stress dependence of permeability were controlled by the mineralogy.