Gas flow mechanisms under the effects of pore structures and permeability characteristics in source rocks of coal measures in Qinshui Basin, China

The gas flow mechanisms in source rocks of coal measures under the effects of the pore structures and permeability characteristics were investigated by field-emission scanning electron microscopy, low-pressure nitrogen gas adsorption, high-pressure mercury intrusion, and pressure pulse decay permeability method. Various flow regimes were distinguished in the pores and fractures of differing scales, and the mass fluxes through the same were calculated using the data obtained by the numerical and experimental investigations. Results indicated that mesopores predominated in shale, while coal contained well-developed mesopores and macropores. In addition, the permeabilities of coal and shale were observed to be significantly anisotropic and highly stress dependent. The cross-sectional area proportions of the pores per unit cross-sectional area of the matrix in the free molecular, transition, and slip flow regimes in shale and coal were determined to be, respectively, 0.2:0.7:0.1 and 0.15:0.6:0.25. In the free molecular and transition flow regimes, the mass flux decreased with increasing reservoir depth, while the reverse was the case in the slip flow regime. Further, in the continuum flow regime, the mass flux was unimodally distributed with respect to the reservoir depth. The total mass flux in coal was greater in the direction perpendicular to the bedding compared to the direction parallel to the bedding, while the reverse was the case in shale. In addition, the continuum flow regime predominated in coal in both the directions perpendicular and parallel to the bedding, but only in the direction parallel to the bedding in shale. This work presents a comprehensive model for the analysis of all the flow regimes in pores and fractures of differing scales, as well as the anisotropy. Findings of the study are meaningful for establishing the coupling accumulation mechanism of the Three Coal Gases and developing a unified exploration and exploitation program.

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title: Measuring anisotropic permeability using a cubic shale sample in a triaxial cell
abstract: Reservoir rocks for water, oil and natural gas, as well as for CO 2 storage are often anisotropic in permeability, due to different pore or layering structures in different directions. Therefore, anisotropic permeability is an important parameter to measure when analysing fluid flow performance in reservoirs. Permeability is commonly measured using a triaxial cell, and anisotropic permeability is often traditionally measured using subcored cylindrical samples from a recovered core. However, the sample's heterogeneity can significantly affect the test results. Cubic samples can eliminate the effect of heterogeneity when measuring anisotropic permeability, but sealing is a major challenge that limits the use of this technique. In this work, a 3D-printed membrane was made to hold cubic shale sample. The cubic sample and 3D-printed membrane assembly which simulate a normal cylindrical core was then installed in a rubber sleeve for permeability measurement in a triaxial cell. Re-orienting the sample in the triaxial cell enabled permeability measurements along each directional axis. Using helium gas to demonstrate the technique, our results show that the shale sample taken from the Longmaxi Formation in Sichuan Basin, China has strong permeability anisotropy, with permeability perpendicular to bedding about 4% of that parallel to bedding. Through reservoir simulation using different permeabilities, we demonstrate that anisotropic permeability has a large impact on modelling gas production, suggesting that anisotropic permeability should be routinely measured and applied to the modelling of fluid flow in reservoir rocks with high permeability anisotropy, such as shales. Our measurement technique can be readily applied to any existing triaxial rigs and will benefit future reservoir evaluation and characterisation.

title: Fracture permeability evaluation of a coal reservoir using geophysical logging: A case study in the Zhengzhuang area, southern Qinshui Basin
abstract: To evaluate the heterogeneity of the No. 3 coal reservoir fracture permeability of Zhengzhuang area in the southern Qinshui Basin, several fracture models were reviewed and their applicability to coal reservoirs was discussed. Fourteen coalbed methane exploration wells with well test data were used to perform an optimization of the fracture parameter models. The results showed that fracture porosity presents a strong correlation with the well test permeability. Fracture porosity was calculated by the dual laterolog iterative method, in which the fracture distortion coefficient Kr was introduced. Based on this correlation, the F-S fracture permeability calculation model was adopted to acquire the fracture permeability of coalbed methane wells in the Zhengzhuang area. The predicted fracture permeability is generally low in the Zhengzhuang area, ranging from 0.01 to 0.37 mD, with an average of 0.07 mD. The planar permeability is strongly heterogeneous. The permeability of the No. 3 coal reservoir is relatively low close to the Shitou and Houchengyao normal faults in the southern Zhengzhuang area, but high in the midwestern Zhengzhuang area, with an average of 0.21 mD. The fracture permeability of the coal reservoir in the vertical direction is in the range of 0.005 to 0.680 mD, decreasing significantly with increasing burial depth. The regional distribution of permeability is mainly controlled by burial depth and in situ stresses. The permeability is high in the shallow area and in the minor concomitant fault zone, but low in the folding area and near major faults. The heterogeneity of the coal reservoir has an important effect on the permeability in the vertical direction. The best prospective target area for coalbed methane production is predicted by the minimum requirements of gas content and thus permeability in this area. The prediction result has a good corresponding relation with the current production capacity of coalbed methane wells.

title: Characteristics of in-situ stress field in Southern Qinshui Basin and its research significance
abstract: Adopted hydraulic fracturing method to measure in-situ stress,obtained in-situ stress distribution of main minable coal seams of 45 coalbed methane testing wells in Southern Qinshui Basin,through statistical analysis,the correlations and their models between in-situ stress in main minable coal seams and the burial depth of coal seam were established,the significance of in-situ stress in research of coal reservoir’s permeability and hydraulic fracturing was analysised.The result shows that the maximum horizontal principal stress in Southern Qinshui Basin is 6.42～41.86 MPa,the average is 17.21 MPa;the maximum horizontal principal stress grads is 1.17～4.79 MPa/100 m,the average is 2.64 MPa/100 m;the minimum horizontal principal stress is 3.30～26.40 MPa,the average is 11.391 MPa,the minimum horizontal principal stress grads is 0.99～2.85 MPa/100 m,the average is 1.77 MPa/100 m.It is also noticed that principal stresses all increase following a linear relationship as coal seam burial depth increase.The coal reservoirs with a burial depth shallower than 650 m,in-situ stress state principally shows σvσhmaxσhmin,the minimum horizontal principal stress is below 12 MPa,recent in-situ stress state is located tension zone;the in-situ stress state of coal reservoirs with 650～1 000 m in depth transforms into σhmax ≈σv≈σhmin,the minimum horizontal principal stress is 12～20 MPa,recent in-situ stress state is situated transition zone which transforms from tension zone into compression zone;the coal reservoirs with 1 000～1 500 m in depth,in-situ stress state is σhmax ≈σv≈σhmin,the minimum horizontal principal stress is over 20 MPa,recent in-situ stress state becomes compression zone.Under the effect of in-situ stress,fissures are tend to closed gradually,and the coal reservoir’s permeability drops rapidly.Simultaneity,in-situ stress produces an important influence on crack propagation of coal reservoir’s hydraulic fracturing,direction of crack propagation is all along the maximum horizontal principal stress’s.

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abstract: Gaseous flow regimes through tight porous media are described by rigorous application of a unified Hagen–Poiseuille-type equation. Proper implementation is accomplished based on the realization of the preferential flow paths in porous media as a bundle of tortuous capillary tubes. Improved formulations and methodology presented here are shown to provide accurate and meaningful correlations of data considering the effect of the characteristic parameters of porous media including intrinsic permeability, porosity, and tortuosity on the apparent gas permeability, rarefaction coefficient, and Klinkenberg gas slippage factor.

title: Knudsen’s Permeability Correction for Tight Porous Media
abstract: Various flow regimes including Knudsen, transition, slip and viscous flows (Darcy’s law), as applied to flow of natural gas through porous conventional rocks, tight formations and shale systems, are investigated. Data from the Mesaverde formation in the United States are used to demonstrate that the permeability correction factors range generally between 1 and 10. However, there are instances where the corrections can be between 10 and 100 for gas flow with high Knudsen number in the transition flow regime, and especially in the Knudsen’s flow regime. The results are of practical interest as gas permeability in porous media can be more complex than that of liquid. The gas permeability is influenced by slippage of gas, which is a pressure-dependent parameter, commonly referred to as Klinkenberg’s effect. This phenomenon plays a substantial role in gas flow through porous media, especially in unconventional reservoirs with low permeability, such as tight sands, coal seams, and shale formations. A higher-order permeability correlation for gas flow called Knudsen’s permeability is studied. As opposed to Klinkenberg’s correlation, which is a first-order equation, Knudsen’s correlation is a second-order approximation. Even higher-order equations can be derived based on the concept used in developing this model. A plot of permeability correction factor versus Knudsen number gives a typecurve. This typecurve can be used to generalize the permeability correction in tight porous media. We conclude that Knudsen’s permeability correlation is more accurate than Klinkenberg’s model especially for extremely tight porous media with transition and free molecular flow regimes. The results from this study indicate that Klinkenberg’s model and various extensions developed throughout the past years underestimate the permeability correction especially for the case of fluid flow with the high Knudsen number.

title: On the experimental evaluation of permeability in porous media using a gas flow method
abstract: Several studies indicate that experimental determination of porous medium permeability by a gas flow method may be influenced by gas properties and ambient temperature. In order to explain these influences, a very simple model is developed based on the idea that the flow in the porous medium may results from both pressure-driven and free molecular flows. Measurements of the permeability of sand and a woven fibrous material performed with air and helium flows seem to corroborate this view. Based on the approach developed, we also study the phenomenon known as slip, and a methodology to quantify the slip length is presented.

title: A unified method to evaluate shale gas flow behaviours in different flow regions
abstract: As pore size of gas shale ranges widely, various flow types including viscous flow, slip flow and Knudsen flow could coexist during shale gas production. Currently, different models have to be applied to describe the gas transport behaviours in different flow regions and the selection of the models is highly dependent on the flow classification criteria. This also brings difficulty in selecting proper gas flow models near the flow region boundaries, which again depends on the flow classification criteria. To address this problem, this study proposes a unified method to describe the gas flow in the whole spectrum of flow regions by transforming all the gas transport equations for different flow types into a general form. The modelling results by the unified method are comparable with that by the previous models, but less input parameters are required for the unified method. Since the unified method provides a continuous permeability kea for all flow regions, it avoids discontinuity at the boundary of different flow regions caused by using piecewise flow models. The method is able to depict the gas permeability evolution with reservoir pressure change and is applied to interpret the literature permeability data and to predict the permeability variation among all the flow regions with different gas pressures and pore sizes. The results illustrate that the flow types may change within a specific pore (especially for small pores) during the pressure depletion in shale gas production and different gas transport mechanisms may coexist for some shales with typical bimodal pore size distribution under a specific gas pressure condition. This work provides a unified way to analyse gas flow behaviours and gas permeability variation in different regions and can be readily applied to the reservoir simulation models to predict the gas production behaviour especially the long term gas production behaviour.